false 2019 --12-31 0.01 P10Y 5 23 17 - - 6 730 FALSE 0001163165 FY 998 1 P30D 283 37.5 56.9 No No <div>Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.</div> <div>*Primarily euro and Norwegian krone.</div> <div>*We paid interest to, or received interest from, various affiliates. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.</div> <div>(1)Sales and other operating revenues are attributable to countries based on the location of the selling operation.</div> <div>(4)Long-lived assets do not include $1,236 million of net PP&E associated with assets held for sale as of December 31, 2019. See Note 5—Acquisitions and Dispositions, for additional information.</div> <div>(2)Defined as net PP&E plus equity investments and advances to affiliated companies.</div> <div>(3)Long-lived assets do not include $426 million of net PP&E associated with assets held for sale as of December 31, 2019. 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2019
 
 
 
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, 2019
 
 
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 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 28, 2019, the last
business day of the registrant’s most recently
 
completed second fiscal quarter, based on
 
the closing price on that date
of $61.00, was $
67.7
 
billion.
 
The registrant had
1,081,132,415
 
shares of common stock outstanding at January 31, 2020.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be
 
held on May 12, 2020 (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
 
...................................................................................................................
 
6
Canada ......................................................................................................................
 
9
Europe and North Africa
 
...........................................................................................
 
10
Asia Pacific and Middle East
 
....................................................................................
 
12
Other International
 
....................................................................................................
 
17
Competition ...................................................................................................................
 
19
General
 
...........................................................................................................................
 
19
1A.
Risk Factors
 
........................................................................................................................
 
21
1B.
Unresolved Staff Comments
 
...............................................................................................
 
28
3.
Legal Proceedings
 
...............................................................................................................
 
28
4.
Mine Safety Disclosures
 
.....................................................................................................
 
28
Information About our Executive Officers
 
.........................................................................
 
29
PART
 
II
5.
Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
 
............................................................................
 
31
6.
Selected Financial Data ......................................................................................................
 
34
7.
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
 
.....................................................................................................
 
35
7A.
Quantitative and Qualitative Disclosures
 
About Market Risk
 
............................................
 
72
8.
Financial Statements and Supplementary
 
Data
 
...................................................................
 
75
9.
Changes in and Disagreements with Accountants
 
on Accounting and
Financial Disclosure
 
.......................................................................................................
 
185
9A.
Controls and Procedures
 
.....................................................................................................
 
185
9B.
Other Information
 
...............................................................................................................
 
185
PART
 
III
10.
Directors, Executive Officers and Corporate Governance
 
..................................................
 
186
11.
Executive Compensation
 
....................................................................................................
 
186
12.
Security Ownership of Certain Beneficial Owners
 
and Management and
 
Related Stockholder Matters
 
..........................................................................................
 
186
13.
Certain Relationships and Related Transactions, and Director
 
Independence....................
 
186
14.
Principal Accounting Fees and Services
 
.............................................................................
 
186
PART
 
IV
15.
Exhibits, Financial Statement Schedules
 
............................................................................
 
187
Signatures ...........................................................................................................................
 
197
 
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
GBP
British pound
ASU
accounting standards update
DD&A
depreciation, depletion and
Units of Measurement
amortization
BBL
barrel
FASB
Financial Accounting Standards
BCF
billion cubic feet
Board
BOE
barrels of oil equivalent
FIFO
first-in, first-out
MBD
thousands of barrels per day
G&A
general and administrative
MCF
thousand cubic feet
GAAP
generally accepted accounting
 
MMBOE
million barrels of oil equivalent
principles
MBOED
thousands of barrels of oil
 
LIFO
last-in, first-out
equivalent per day
NPNS
normal purchase normal sale
MMBTU
million British thermal units
PP&E
properties, plants and equipment
MMCFD
million cubic feet per day
SAB
staff accounting bulletin
VIE
variable interest entity
Industry
CBM
coalbed methane
Miscellaneous
E&P
exploration and production
EPA
Environmental Protection Agency
FEED
front-end engineering and design
EU
European Union
FPS
floating production system
FERC
Federal Energy Regulatory
 
FPSO
floating production, storage and
Commission
offloading
GHG
greenhouse gas
JOA
joint operating agreement
HSE
health, safety and environment
LNG
liquefied natural gas
ICC
International Chamber of
 
NGLs
natural gas liquids
Commerce
OPEC
Organization of Petroleum
 
ICSID
World Bank’s
 
International
 
Exporting Countries
Centre for Settlement of
PSC
production sharing contract
Investment Disputes
PUDs
proved undeveloped reserves
IRS
Internal Revenue Service
SAGD
steam-assisted gravity drainage
OTC
over-the-counter
WCS
Western Canada Select
NYSE
New York Stock Exchange
WTI
West Texas
 
Intermediate
SEC
U.S. Securities and Exchange
Commission
TSR
total shareholder return
U.K.
United Kingdom
U.S.
United States of America
 
 
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
 
21 and “CAUTIONARY STATEMENT
 
FOR THE
PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS
 
OF THE PRIVATE
 
SECURITIES LITIGATION
REFORM ACT OF 1995,” beginning on page
 
 
 
Items 1 and 2.
 
BUSINESS AND PROPERTIES
 
 
CORPORATE STRUCTURE
 
ConocoPhillips is an independent E&P company
 
with operations and activities in 17 countries.
 
Our diverse,
low cost of supply portfolio includes resource-rich
 
unconventional plays in North America;
 
conventional
assets in North America, Europe, Asia and Australia;
 
LNG developments; oil sands assets in Canada;
 
and an
inventory of global conventional and unconventional
 
exploration prospects.
 
Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately
 
10,400 people worldwide and had total assets
 
of
 
$71
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.
 
 
 
SEGMENT AND GEOGRAPHIC INFORMATION
 
For operating segment and geographic information,
 
see Note 25—Segment Disclosures and Related
Information, in the Notes to Consolidated Financial
 
Statements, which is incorporated herein by reference.
 
 
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on
 
a worldwide
basis.
 
At December 31, 2019, our operations were
 
producing in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, Malaysia, Libya, China and
 
Qatar.
 
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3
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 located in politically
 
stable 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
2019
2018
2017
Crude oil
Consolidated operations
2,562
2,533
2,322
Equity affiliates
73
78
83
Total Crude Oil
2,635
2,611
2,405
Natural gas liquids
Consolidated operations
361
349
354
Equity affiliates
39
42
45
Total Natural Gas Liquids
400
391
399
Natural gas
Consolidated operations
1,209
1,265
1,267
Equity affiliates
736
760
717
Total Natural Gas
1,945
2,025
1,984
Bitumen
Consolidated operations
282
236
250
Total Bitumen
282
236
250
Total consolidated operations
4,414
4,383
4,193
Total equity affiliates
848
880
845
Total company
5,262
5,263
5,038
 
 
Total production of 1,348 MBOED increased 5 percent in 2019 compared with 2018.
 
 
The increase in total
average production primarily resulted from new wells
 
online in the Lower 48; an increased interest in
 
the
Western North Slope (WNS) and Greater Kuparuk Area (GKA) of Alaska following
 
acquisitions closed in
2018; and higher production in Norway due to drilling
 
activity and the startup of Aasta Hansteen
 
in December
2018.
 
The increase in production was partly offset by normal
 
field decline and disposition impacts,
 
primarily
from the U.K. asset sale in 2019 and non-core
 
asset sales in the Lower 48 during 2018.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4
Production excluding Libya was 1,305 MBOED in
 
2019 compared with 1,242 MBOED in 2018, an
 
increase of
63 MBOED or 5 percent.
 
Underlying production, which excludes Libya and
 
the net volume impact from
closed dispositions and acquisitions of 51 MBOED
 
in 2019 and 47 MBOED in 2018, is used to measure
 
our
ability to grow production organically.
 
Our underlying production grew 5 percent to
 
1,254 MBOED in 2019
from 1,195 MBOED in 2018.
 
Our worldwide annual average realized price
 
was $48.78 per BOE in 2019,
 
a decrease of 9 percent compared
with $53.88 per BOE in 2018,
 
reflecting weaker marker prices as a result of
 
macroeconomic demand concerns.
 
Our worldwide annual average crude oil price
 
decreased 10 percent, from $68.13 per barrel
 
in 2018 to $60.99
per barrel in 2019.
 
Additionally, our worldwide annual average NGL prices decreased 34 percent,
 
from
$30.48 per barrel in 2018 to $20.09 per barrel in
 
2019.
 
Our worldwide annual average natural gas price
decreased 11 percent, from $5.65 per MCF in 2018 to $5.03 per MCF
 
in 2019.
 
Average annual bitumen prices
increased 42 percent, from $22.29 per barrel in 2018
 
to $31.72 per barrel in 2019.
 
 
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 1.32 million net undeveloped
 
acres at
year-end 2019.
 
Alaska operations contributed 25 percent
 
of our worldwide liquids production and less
 
than 1
percent of our natural gas production.
 
 
2019
Interest
Operator
Liquids
MBD
Natural Gas
MMCFD
Total
MBOED
Average Daily Net Production
Greater Prudhoe Area
36.1
%
BP
81
4
81
Greater Kuparuk Area
91.4-94.7
ConocoPhillips
86
2
86
Western North Slope
100.0
ConocoPhillips
50
1
51
Total Alaska
217
7
218
 
 
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
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.
 
 
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 Prudhoe
 
Bay.
 
Field installations
include three central production facilities
 
which separate oil, natural gas and water, as well as a separate
seawater treatment plant.
 
Development drilling at Kuparuk consists of
 
rotary-drilled wells and horizontal
multi-laterals from existing well bores utilizing
 
coiled-tubing drilling.
 
 
 
 
 
 
5
 
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.
 
Alpine is located 34 miles west of Kuparuk.
 
In 2015, first oil was
achieved at Alpine West CD5,
 
a drill site which extends the Alpine reservoir west
 
into the National Petroleum
Reserve-Alaska (NPR-A).
 
In 2019, we continued drilling additional
 
wells using the available well slots on this
pad.
 
 
The Greater Mooses Tooth Unit, the first unit established entirely within the
 
NPR-A, was formed in 2008.
 
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 the fourth quarter of 2018 and completed drilling in
2019.
 
We expect first oil from GMT-2 in 2021.
 
 
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.
 
AGDC decided to continue on
its own.
 
In 2019, affiliates of ExxonMobil and BP agreed
 
to each contribute up to $5 million or approximately
one third of AGDC’s anticipated costs for full-year 2020.
 
In 2020, AGDC will be focused on permitting
efforts, the most important of which is the National Environmental
 
Protection Act process before the FERC.
 
FERC’s final milestones are the Publication of Notice of Availability of Final Environmental Impact
Statement, which is scheduled for March 6, 2020,
 
and the Issuance of Final Order, which is scheduled for June
4, 2020.
 
AGDC has recently contracted with Fluor
 
Corporation to evaluate cost reduction opportunities
 
in
preparation for soliciting partners for the project.
 
We continue to be willing to sell our North Slope gas to the
project but do not plan to take an equity position.
 
 
Exploration
Appraisal of the Willow Discovery, located in the northeast portion of the NPR-A, continued
 
throughout 2019
with five appraisal wells.
 
In 2020, we will continue appraisal of
 
the Willow Discovery and explore the
Harpoon Prospect, located southwest of Willow.
 
In 2019, we drilled the West Willow-2 well to appraise the 2018 West Willow oil discovery.
 
 
In late 2018, we commenced appraisal of the Putu
 
Discovery with a long reach well from
 
existing Alpine CD4
infrastructure.
 
The CD4 appraisal well finished drilling
 
and flow tested in 2019.
 
A supporting injector well
was drilled in late 2019 for a 2020 injectivity test.
 
The Cairn 2S-315 Well was drilled in late 2018 from the 2S drill site on state leases
 
in the Kuparuk River Unit.
 
A long-term flow test was commenced in 2019 and
 
evaluations are ongoing.
 
 
A 3-D
 
seismic survey was completed in 2018 over
 
a 250-mile area on state lands.
 
We are currently evaluating
this seismic data for future exploration opportunities.
 
We were successful in the federal lease sale on the North Slope in the fourth quarter
 
of 2019, where we were
the high bidder on three tracts for a total of
 
approximately 33,000 net acres.
 
 
Acquisitions
In the third quarter of 2019, we completed the
 
Nuna discovery acreage acquisition, expanding
 
the Kuparuk
River Unit by 21,000 acres and leveraging legacy
 
infrastructure.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6
 
Transportation
We transport the petroleum liquids produced on the North Slope to south central
 
Alaska through an 800-mile
pipeline that is part of Trans-Alaska Pipeline System (TAPS).
 
We have a 29.1
 
percent ownership interest in
TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines
 
on the North Slope.
 
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope
production, using five company-owned, double-hulled
 
tankers,
 
and charters third-party vessels as necessary.
 
The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.
 
 
LOWER 48
 
The Lower 48 segment consists of operations located
 
in the contiguous U.S. and the Gulf of Mexico.
 
Organized into the Gulf Coast and Great Plains business
 
units, we hold 10.4
 
million net onshore and offshore
acres, with a portfolio of conventional production from
 
legacy assets as well as newer production from
 
our low
cost of supply, shorter cycle time, resource-rich unconventional plays.
 
Based on 2019 production volumes, the
Lower 48 is the company’s largest segment and contributed 39 percent of our
 
worldwide liquids production
and 22 percent of our natural gas production.
 
 
2019
Interest
Operator
Liquids
MBD
Natural Gas
MMCFD
Total
MBOED
Average Daily Net Production
Eagle Ford
Various
%
Various
174
251
216
Gulf of Mexico
Various
Various
15
11
16
Gulf Coast—Other
Various
Various
3
9
5
 
Total Gulf Coast
192
271
237
Bakken
Various
Various
82
92
97
Permian Unconventional
Various
Various
40
94
56
Permian Conventional
Various
Various
20
59
30
Anadarko Basin
Various
Various
5
58
14
Wyoming/Uinta
Various
Various
-
36
6
Niobrara*
Various
Various
8
12
11
 
Total Great Plains
155
351
214
Total Lower 48
347
622
451
*Classified as held-for-sale as of December 31, 2019.
 
See 'Dispositions' below for additional information.
 
 
Onshore
We hold 10.3
 
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 1.7 million net acres in the following
 
areas:
 
 
 
610,000 net acres in the Bakken, located in
 
North Dakota and eastern Montana.
 
 
234,000 net acres in Central Louisiana, where
 
we recently announced our intention to
 
discontinue
exploration activities.
 
201,000 net acres in the Eagle Ford, located in South
 
Texas.
 
 
167,000 net acres in the Permian, located in West Texas and southeastern New Mexico.
 
98,000 net acres in the Niobrara, located in northeastern
 
Colorado.
 
 
363,000 net acres in other areas with unconventional
 
potential.
 
 
 
 
7
 
The majority of our 2019 onshore production
 
originated from the Big 3—Eagle Ford,
 
Bakken and Permian
Unconventional.
 
Onshore activities in 2019 were centered mostly
 
on continued development of assets, with an
emphasis on areas with low cost of supply, particularly in growing unconventional
 
plays.
 
Our major focus
areas in 2019 included the following:
 
 
 
Eagle Ford—The Eagle Ford continued full-field
 
development in 2019.
 
We operated seven rigs on
average in 2019, resulting in 155 operated wells
 
drilled and 166 operated wells brought online.
 
Production increased 16 percent in 2019 compared
 
with 2018, averaging 216 MBOED and 186
MBOED, respectively.
 
 
Bakken—We operated an average of three rigs during the year in the Bakken and participated
 
in
additional development activities operated by co-venturers.
 
We continued our pad drilling with 62
operated wells drilled during the year and 44
 
operated wells brought online.
 
Production increased 15
percent in 2019
 
compared with 2018, averaging 97 MBOED
 
and 84 MBOED, respectively.
 
 
Permian Basin—The Permian Basin is a combination
 
of legacy conventional and unconventional
assets.
 
We operated an average of three rigs during the year in the Permian Basin, resulting
 
in 29
operated wells drilled and 35 operated wells brought
 
online.
 
The Permian Basin produced 86
MBOED in 2019, increasing 30 percent compared
 
with 2018, including 56 MBOED of
unconventional production.
 
Gulf of Mexico
At year-end 2019, 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 nonoperated working interest in
 
the unitized Ursa Field located in the Mississippi
 
Canyon
Area.
 
15.9 percent nonoperated working interest in
 
the Princess Field, a northern subsalt extension
 
of the
Ursa Field.
 
12.4 percent nonoperated working interest in
 
the unitized K2 Field, comprised of seven blocks
 
in the
Green Canyon Area.
 
Dispositions
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
 
Qatar Liquefied Gas Company Limited (3) (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.
 
In the fourth quarter of 2019, we completed the sale
 
of our interests
 
in the Magnolia Field in the Gulf of
Mexico.
 
Production from this disposed asset
 
was less than one MBOED in 2019.
 
In the fourth quarter of 2019, we entered into an
 
agreement to sell our interests in the Niobrara,
 
with an
anticipated closing date in the first quarter
 
of 2020.
 
Production from the interests to be disposed
 
was
approximately 11 MBOED in 2019.
 
In January 2020, we entered into an agreement to
 
sell our interests in certain non-core properties
 
for $186
million, plus customary adjustments.
 
The assets met the held for sale criteria in January
 
2020 and the
transaction is expected to be completed in the
 
first quarter of 2020.
 
This disposition will not have a significant
impact on Lower 48 production.
 
 
For additional information on these transactions,
 
see Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
 
 
8
 
Exploration
 
Our exploration focus is on onshore unconventional
 
plays, which in 2019 included the Delaware
 
in the
Permian Basin, and the Eagle Ford in south Texas.
 
In the third quarter of 2019, we announced our
 
decision to
discontinue exploration activities in the Central
 
Louisiana Austin Chalk.
 
Facilities
 
 
Lost Cabin Gas Plant—We operate and own a 46 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 second half of 2020.
 
The expected production loss in 2020 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
CANADA
 
Our Canadian operations mainly consist of the
 
Surmont oil sands development in Alberta
 
and the liquids-rich
Montney unconventional play in British Columbia.
 
In 2019, operations in Canada contributed
 
7 percent of our
worldwide liquids production and less than 1 percent
 
of our natural gas production.
 
2019
Natural
Liquids
Gas
Bitumen
Total
Interest
Operator
MBD
MMCFD
MBD
MBOED
Average Daily Net Production
Surmont
50.0
%
ConocoPhillips
-
-
60
60
Montney
100.0
ConocoPhillips
1
9
-
3
Total Canada
1
9
60
63
 
 
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 0.6 million 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.
 
The second phase of the Surmont Project achieved
 
first production in
2015 and reached peak production in 2018.
 
We are focused on structurally lowering costs, reducing GHG
intensity and optimizing asset performance.
 
 
The Alberta government imposed a production
 
curtailment impacting the industry beginning
 
in January 2019.
 
The curtailment measure,
 
which impacted our annualized average production
 
by 3 MBOED in 2019, is
intended to strengthen the WCS differential to WTI at
 
Hardisty.
 
The curtailment program is established and
administered by the Alberta Energy Regulator under the
Curtailment Rules
 
regulation, which is currently set to
expire on December 31, 2020.
 
Montney
We hold approximately 151,000 net acres in the emerging unconventional Montney play
 
in northeast British
Columbia.
 
Our Montney activity in 2019 included drilling
 
16 horizontal wells, completing 14 horizontal
 
wells
and acquiring approximately 6,000 additional net
 
acres.
 
Production from our 2019 drilling program
commenced in February 2020 following the completion
 
of third-party offtake facilities.
 
Appraisal drilling and completions activity
 
will continue in 2020 to further explore the area’s resource
potential.
 
Exploration
 
Our primary exploration focus is assessing our
 
Montney onshore unconventional acreage
 
in Western Canada.
 
Additionally, we have exploration acreage in the Mackenzie Delta/Beaufort
 
Sea Region and the Arctic Islands.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10
EUROPE AND NORTH AFRICA
 
The Europe and North Africa segment consisted
 
of operations in Norway, Libya and the U.K. and exploration
activities in Norway and Libya.
 
In 2019, operations in Europe and North Africa contributed
 
16 percent of our
worldwide liquids production and 17 percent of natural
 
gas production.
 
 
Norway
2019
Liquids
Natural Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Ekofisk Area
35.1
%
ConocoPhillips
50
44
57
Heidrun
24.0
Equinor
14
29
19
Alvheim
20.0
Aker BP
10
12
12
Visund
9.1
Equinor
4
46
12
Aasta Hansteen
10.0
Equinor
-
64
11
Troll
1.6
Equinor
2
49
10
Other
Various
Equinor
8
10
10
Total Norway
88
254
131
 
 
The Greater Ekofisk Area is located approximately
 
200 miles offshore Stavanger, Norway, in the North Sea,
and comprises three producing fields: Ekofisk,
 
Eldfisk and Embla.
 
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, including
 
the Ekofisk South and Eldfisk II developments.
 
Continued
development drilling in the Greater Ekofisk
 
Area is expected to contribute additional production
 
over the
coming years, as additional wells come online.
 
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.
 
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.
 
Aasta Hansteen is located in the Norwegian
 
Sea and achieved first production in December
 
2018.
 
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.
 
We also have varying ownership interests in two other producing fields in the Norway
 
sector of the North Sea.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11
Exploration
 
In 2019, we operated the Busta and Enniberg exploration
 
wells in Block 25/7 in the North Sea.
 
The Busta well
encountered hydrocarbons and will be evaluated
 
for future appraisal consideration.
 
The Enniberg well
encountered insufficient hydrocarbons and was expensed
 
as a dry hole in 2019.
 
We also participated in the
Canela exploration well in the Heidrun area of the
 
Norwegian Sea.
 
The well encountered hydrocarbons and
will be further evaluated to determine commerciality.
 
In 2019, we were awarded two new exploration
licenses; PL1001 and PL1009; and one acreage
 
addition, PL782SD.
 
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.
 
United Kingdom
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Britannia Satellites*
26.3–93.8
%
ConocoPhillips
7
55
16
J-Area
32.5–36.5
ConocoPhillips
6
38
12
Britannia
58.7
ConocoPhillips
2
49
10
East Irish Sea
100.0
Spirit Energy
-
48
8
Clair
7.5
BP
4
1
4
Other
Various
Various
-
2
-
Total United Kingdom
19
193
50
*Includes the Chevron-operated Alder Field, ConocoPhillips equity interest was 26.3 percent.
 
 
On September 30, 2019, we completed the sale of
 
two ConocoPhillips U.K. subsidiaries
 
to Chrysaor E&P
Limited, including all of our producing assets
 
in the U.K.
 
Annualized average production from the assets
 
sold
was 50 MBOED in 2019.
 
For additional information on this transaction,
 
see Note 5—Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial
 
Statements.
 
 
We retained our Teesside,
 
England oil terminal, where we are the operator
 
and have a 40.25 percent ownership
interest, to support our Norway operations.
 
 
Libya
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Waha Concession
16.3
%
Waha Oil Co.
38
31
43
Total Libya
38
31
43
 
 
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 2019, we had 19 crude
liftings from Es Sider.
 
The number of crude liftings from the Es Sider
 
crude oil export terminal in 2020 is
uncertain due to civil unrest.
 
In January 2020, we declared Force Majeure to
 
our crude shippers following the
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12
blockade of the Es Sider crude oil export terminal
 
and the declaration of Force Majeure by the
 
National Oil
Corporation of Libya.
 
 
ASIA PACIFIC AND MIDDLE EAST
 
The Asia Pacific and Middle East segment has
 
exploration and production operations
 
in China, Indonesia,
Malaysia and Australia and producing operations
 
in Qatar and Timor-Leste.
 
In 2019, operations in the Asia
Pacific and Middle East segment contributed 13
 
percent of our worldwide liquids production
 
and 60 percent of
natural gas production.
 
 
Australia and Timor-Leste
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
ConocoPhillips/
Australia Pacific LNG
37.5
%
Origin Energy
-
679
113
Bayu-Undan*
56.9
ConocoPhillips
10
194
43
Athena/Perseus*
50.0
ExxonMobil
-
31
5
Total Australia and Timor-Leste
10
904
161
*This asset is held-for-sale as of December 31, 2019.
 
See Note 5—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 3,900 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, 2019, APLNG has an outstanding
 
balance of $6.7 billion on a $8.5 billion
 
project finance
facility.
 
In late 2018 and early 2019, APLNG successfully
 
refinanced $4.6 billion of the project finance
facility through three separate transactions,
 
which added lower cost United States Private
 
Placement (USPP)
bond and commercial bank facilities.
 
In conjunction with these transactions, APLNG
 
made voluntary
repayments of $2.2 billion to a syndicate of
 
Australian and international commercial banks
 
and fully
extinguished $2.4 billion of financing from the
 
Export-Import Bank of China.
 
Project finance interest
payments are bi-annual, concluding September
 
2030.
 
For additional information, see Note 3—Variable Interest Entities,
 
Note 6—Investments, Loans and Long-
Term Receivables and Note 12—Guarantees, in the Notes to Consolidated
 
Financial Statements.
 
 
 
 
 
 
 
13
Bayu-Undan
The Bayu-Undan gas condensate field is
 
located in the Timor Sea Joint Petroleum Development Area between
Timor-Leste and Australia.
 
We also operate and own a 56.9 percent interest in the associated Darwin LNG
Facility, located at Wickham Point, Darwin.
 
The Bayu-Undan natural gas recycle facility
 
processes wet gas; separates, stores and offloads condensate,
propane and butane; and re-injects dry gas back
 
into the reservoir.
 
In addition, a 310-mile natural gas pipeline
connects the facility to the 3.5-million-metric-tonnes-per-year
 
capacity Darwin LNG Facility.
 
Produced
natural gas is piped to the Darwin LNG Plant, where
 
it is converted into LNG before being transported
 
to
international markets.
 
In 2019, we sold 133 billion gross cubic feet
 
of LNG primarily to utility customers
 
in
Japan.
 
Athena/Perseus
The Athena production license (WA-17-L) in which we had a 50 percent working interest is located
 
offshore
Western Australia and our entitlement to production ended in the fourth quarter of 2019.
 
Annualized average
production from this license was five MBOED in
 
2019.
 
 
 
Exploration
We operate three exploration permits in the Browse Basin, offshore northwest Australia, in which
 
we own a 40
percent interest in permits WA-315-P,
 
WA-398-P and TP 28, of the Greater Poseidon
 
Area.
 
Phase I of the
Browse Basin drilling campaign resulted in
 
three discoveries in the Greater Poseidon Area and
 
Phase II
resulted in five additional discoveries.
 
All wells have been plugged and abandoned.
 
 
We operate two retention leases in the Bonaparte Basin, offshore northern Australia, where we
 
own a 37.5
percent interest in the Barossa and Caldita discoveries.
 
In April 2018, Barossa entered the FEED phase
 
of
development which continued
 
through 2019.
 
During the FEED phase, costs and the technical
 
definition for the
project will be finalized, gas and condensate sales
 
agreements progressed, and access arrangements
 
negotiated
with the owners of the Darwin LNG Facility
 
and Bayu-Darwin Pipeline.
 
In December 2019, we entered into an agreement
 
with 3D Oil to acquire a 75 percent interest
 
and operatorship
of an offshore Tasmanian Permit located in the Otway Basin.
 
The farm-in agreement is conditional upon the
agreement and signing of a JOA by both parties
 
and required government approvals.
 
We plan to conduct a 3D
seismic survey in the second half of 2020.
 
This activity is excluded from the dispositions
 
discussed below.
 
Dispositions
In the second quarter of 2019, we completed the sale
 
of our 30 percent interest in the Greater Sunrise
 
Fields to
the government of Timor-Leste.
 
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos with an expected completion
 
date in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent.
 
These subsidiaries hold our 37.5 percent interest
 
in the
Barossa Project and Caldita Field, our 56.9 percent
 
interest in the Darwin LNG Facility and Bayu-Undan
Field, our 40 percent interest in the Greater
 
Poseidon Fields, and our 50 percent interest
 
in the Athena Field.
 
Production associated with the Australia-West assets to be sold was 48 MBOED in
 
2019.
 
 
For additional information on these transactions,
 
see Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
14
Indonesia
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
South Sumatra
54
%
ConocoPhillips
2
321
56
Total Indonesia
2
321
56
 
 
During 2019, we operated
 
three PSCs in Indonesia:
 
the Corridor Block and South Jambi “B,” both
 
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.
 
Production from the South Jambi “B” PSC has reached
 
depletion and field development has been suspended.
 
This PSC expired
 
on January 26, 2020 and has been returned to
 
the Government of Indonesia.
 
 
Exploration
 
We hold a 60 percent working interest in the Kualakurun PSC.
 
After completion of prospect evaluation,
 
we
and the other joint venture partners decided to relinquish
 
all of the remaining acreage to the Government
 
of
Indonesia.
 
 
Transportation
We are a 35 percent owner of a consortium company that has a 40 percent ownership
 
in PT Transportasi Gas
Indonesia, which owns and operates the Grissik
 
to Duri and Grissik to Singapore natural
 
gas pipelines.
 
China
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Penglai
49.0
%
CNOOC
29
-
29
Panyu
24.5
CNOOC
6
-
6
Total China
35
-
35
 
 
Penglai
The
 
Penglai
 
19-3,
 
19-9
 
and
 
25-6
 
fields
 
are
 
located
 
in
 
Bohai
 
Bay
 
Block
 
11/05
 
and
 
are
 
in
 
various
 
stages
 
of
development.
 
As
 
part
 
of
 
further
 
development
 
of
 
the
 
Penglai
 
19-9
 
Field,
 
the
 
wellhead
 
platform
 
J
 
Project
 
achieved
 
first
production in 2016.
 
This project will
 
include 62 wells,
 
57 of
 
which have
 
been completed and
 
brought online
through December 2019.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15
The
 
Penglai
 
19-3/19-9
 
Phase
 
3
 
Project
 
consists
 
of
 
three
 
new
 
wellhead
 
platforms
 
and
 
a
 
central
 
processing
platform.
 
First oil from Phase 3 was achieved in 2018 for two of
 
the platforms, with the third platform planned
to come
 
online in
 
the second
 
quarter of
 
2020.
 
This project
 
could include
 
up to
 
186 wells,
 
42 of
 
which have
been completed and brought online through December
 
2019.
 
 
In December 2018, we sanctioned the Penglai 25-6
 
Phase 4A Project.
 
This project consists of one new
wellhead platform and anticipates 62 new wells.
 
First production is expected in 2021.
 
 
Panyu
Our production license for Panyu 4-2, 5-1 and
 
11-6 located in Block 15/34 in the South China Sea expired
 
in
September 2019.
 
Annualized average production from these licenses
 
were six MBOED in 2019.
 
We still have a license for Panyu 4-1 in Block 15/34 and are evaluating this area for potential
 
development.
 
Exploration
Exploration activities in the Bohai Penglai Field during
 
2019 consisted of two successful appraisal
 
wells, a
full-field 3-D seismic program covering existing and
 
future development opportunities, and an infill
compressive seismic imaging (CSI) survey to improve
 
imaging beneath the gas cloud in support
 
of future
development projects.
 
In Block 15/34,
 
one exploration well was drilled in the Panyu
 
4-1E prospect and was
expensed as a dry hole.
 
Malaysia
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Gumusut
29.0
%
Shell
23
-
23
Kebabangan (KBB)
30.0
KPOC
3
91
18
Malikai
35.0
Shell
15
-
15
Siakap North-Petai
21.0
PTTEP
1
-
1
Total Malaysia
42
91
57
 
We have varying stages of exploration, development and production activities across
 
2.2 million net acres in
Malaysia, with working interests in six PSCs.
 
Three of these PSCs are located off the eastern Malaysian
 
state
of Sabah: Block G, Block J and the Kebabangan
 
Cluster (KBBC).
 
We operated
 
three exploration blocks,
Block SK304, Block SK313 and Block WL4-00,
 
off the eastern Malaysian state of Sarawak.
 
Block J
Gumusut
First production from the Gumusut Field occurred
 
from an early production system in
 
2012.
 
Production from
a permanent, semi-submersible Floating Production
 
System was achieved in 2014.
 
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.
 
 
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.
 
 
KBB
First production from the KBB gas field was
 
achieved in 2014.
 
During 2019, KBB tied-in to a nearby third-
party floating LNG vessel which provided increased
 
gas offtake capacity.
 
Production in 2020 is anticipated to
be impacted between 15 to 20 MBOED due to the
 
rupture of a third-party pipeline, in January 2020,
 
which
 
 
 
 
 
 
 
 
 
 
 
 
 
16
carries gas production from the KBB gas field to
 
market.
 
The extent of the required pipeline repairs, and the
amount of time required to return this pipeline
 
to full service is still being evaluated.
 
 
Kamunsu East
Development options for the Kamunsu East gas field
 
are being evaluated.
 
 
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 6-
well drilling campaign that will commence in 2020,
 
reached a final investment decision in
 
late 2019.
 
Siakap North-Petai
We hold a 21 percent working interest in the unitized Siakap North-Petai oil field.
 
Exploration
In 2016, we entered into a farm-in agreement to
 
acquire a 50 percent working interest in Block SK
 
313, a 1.4
million gross-acre exploration block offshore Sarawak,
 
with an effective date of January 2017.
 
Following
completion of the Sadok-1 exploration well in January
 
2017, we assumed operatorship of the block
 
from
PETRONAS and completed a 3-D seismic survey.
 
We have no plans for further exploration activity in this
block.
 
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.
 
 
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.
 
The Gemilang-1 exploration well in Block J
 
was completed in late 2018.
 
Development options are being
evaluated.
 
 
 
Qatar
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Qatargas Operating
QG3
30.0
%
Company Limited
21
373
83
Total Qatar
21
373
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.
 
 
 
 
17
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.
 
 
OTHER INTERNATIONAL
 
The Other International segment includes exploration
 
activities in Colombia, Chile and Argentina and
contingencies associated with prior operations.
 
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, ConocoPhillips filed two separate Force
Majeure requests before the competent authority
 
for both blocks, which were granted.
 
Chile
 
We have a 49 percent interest in the Coiron Block located in the Magallanes Basin
 
in southern Chile.
 
 
Argentina
In January 2019, we secured a 50 percent nonoperated
 
interest in the El Turbio Este Block, within the Austral
Basin in southern Argentina.
 
In 2019, we acquired and processed 3-D
 
seismic covering approximately 500
square miles,
 
with evaluation of the data ongoing.
 
In November 2019, we acquired interests in
 
two nonoperated blocks in the Neuquén Basin
 
targeting the Vaca
Muerta play.
 
We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest
 
in the
Aguada Federal Block.
 
In Bandurria Norte, one vertical and four horizontal
 
wells were tested and shut-in
during 2019.
 
In Aguada Federal, two horizontal wells
 
were being tested at the end of the year.
 
Venezuela and Ecuador
For discussion of our contingencies in Venezuela and Ecuador, see Note 13—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
 
 
 
 
 
 
18
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.
 
 
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.
 
For additional
information, see Note 3—Variable Interest Entities, in the Notes to Consolidated Financial
 
Statements.
 
 
Subsea Well Response Project (SWRP)
In 2011, we, along with several leading oil and gas companies, launched
 
the SWRP, a non-profit organization
based in Stavanger, Norway, which was created to enhance the industry’s capability to respond to international
subsea well control incidents.
 
Through collaboration with Oil Spill Response
 
Limited, a non-profit
organization in the U.K., subsea well intervention equipment
 
is available for the industry to use in the event
 
of
a subsea well incident.
 
This complements the work being undertaken
 
in the U.S. by MWCC and 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
 
United
States and Alaska Clean Seas and Ship Escort/Response
 
Vessel
 
System for the Alaska North Slope and Prince
William Sound, respectively.
 
Internationally, we maintain memberships in various 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.
 
Our Optimized Cascade
®
 
LNG liquefaction technology business continues
 
to be successful with the demand
for new LNG plants.
 
The technology has been licensed for use in 26
 
LNG trains around the world, with
feasibility studies ongoing for additional
 
trains.
 
 
19
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, 2019.
 
No difference exists between our estimated total proved
 
reserves
for year-end 2018 and year-end 2017, which are shown in
 
this filing, and estimates of these reserves shown
 
in
a filing with another federal agency in 2019.
 
 
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, including approximately
 
75 billion cubic feet
related to the noncontrolling interests of consolidated
 
subsidiaries, and 172 million barrels of
 
crude oil in the
future.
 
These contracts have various expiration dates
 
through the year 2030.
 
We expect to fulfill the majority
of these delivery commitments with proved developed
 
reserves.
 
In addition, we anticipate using PUDs and
spot market purchases to fulfill any remaining
 
commitments.
 
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
 
2,
 
2019, issue of the
Oil and Gas Journal
, we were the
third-largest U.S.-based oil and gas company in worldwide
 
natural gas and liquids production and worldwide
liquids reserves in 2018.
 
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.
 
 
GENERAL
 
At the end of 2019, we held a total of 942 active
 
patents in 50 countries worldwide, including
 
371 active U.S.
patents.
 
During 2019, we received 64 patents in the
 
U.S. and 90 foreign patents.
 
Our products and processes
generated licensing revenues of $69 million related
 
to activity in 2019.
 
The overall profitability of any
business segment is not dependent on any single
 
patent, trademark, license, franchise or
 
concession.
 
 
 
20
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 60 through
 
65 under the captions “Environmental” and “Climate
 
Change”
is incorporated herein by reference.
 
It includes information on expensed and
 
capitalized environmental costs
for 2019 and those expected for 2020 and 2021.
 
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
.
 
21
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 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.
 
Our operating results, our future rate of growth
 
and the carrying value of our assets are exposed
 
to the
effects of changing commodity prices.
 
Prices for crude oil, bitumen, natural gas, NGLs and
 
LNG can fluctuate widely.
 
Brent crude oil prices
averaged $64 per barrel in 2019, ranging from
 
a low of $53 per barrel in January to a high of almost
 
$75 per
barrel in April.
 
Given volatility in commodity price drivers
 
and the worldwide political and economic
environment generally, as well as increased uncertainty generated by recent (and
 
potential future) armed
hostilities in various oil-producing regions around the
 
globe, price trends may continue to be volatile.
 
Our
revenues, operating results and future rate of growth
 
are highly dependent on the prices
 
we receive for our
crude oil, bitumen, natural gas, NGLs and
 
LNG.
 
The factors influencing these prices are
 
beyond our control.
 
 
Lower crude oil, bitumen, natural gas, NGL and
 
LNG prices may have a material adverse effect on our
revenues, operating income, cash flows and liquidity, and may also affect the amount
 
of dividends we elect to
declare and pay on our common stock and the
 
amount of shares we elect to acquire as
 
part of the share
repurchase program and the timing of such acquisitions.
 
Lower prices may also limit the amount of reserves
we can produce economically, adversely affecting our proved reserves, reserve replacement
 
ratio and
accelerating the reduction in our existing reserve levels
 
as we continue production from upstream
 
fields.
 
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 the past three years, we recognized several
 
impairments, which are described in
Note 9—Impairments and the “APLNG” section
 
of Note 6—Investments, Loans and Long-Term Receivables,
in the Notes to Consolidated Financial Statements.
 
If commodity prices remain low relative
 
to their 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.
 
Although it is not reasonably
practicable to quantify the impact of any future
 
impairments at this time, our results of operations
 
could be
adversely affected as a result.
 
 
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.
 
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.
 
 
22
Additionally, as of December 31, 2019, $5.4 billion of repurchase authority
 
remained of the $15 billion share
repurchase program our Board of Directors had
 
authorized.
 
In February, 2020, our Board of Directors
approved an increase to our repurchase authorization
 
from $15 billion to $25 billion, to support
 
our plan for
future share repurchases.
 
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.
 
 
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.
 
We may need additional capital in the future, and it may not be available on acceptable
 
terms.
 
 
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 collected approximately $0.8 billion of the
$2.0 billion settlement in 2018 and 2019.
 
PDVSA has defaulted on its remaining payment
 
obligations under
this agreement, we are therefore now forced to
 
incur additional costs as we seek to recover any
 
unpaid amounts
under the agreement.
 
23
 
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 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.
 
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.
 
 
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 in the U.S. and in other
 
countries in
which we operate.
 
For a description of the most significant of these
 
environmental laws and regulations, see
the “Contingencies—Environmental” section
 
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.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.
 
Exploration and production activities in
 
certain areas, such as offshore environments, arctic fields,
 
oil
sands reservoirs and unconventional plays.
 
 
24
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 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. announced its intention to withdraw
 
from the Paris Agreement, there is no guarantee
 
that the
commitments made by the U.S. will not be implemented,
 
in whole or in part, by U.S. state and local
governments or by major corporations headquartered
 
in the U.S.
 
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.
 
 
Additionally, increasing attention to global climate change has resulted in pressure
 
upon shareholders,
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,
 
which could increase our costs or otherwise
 
adversely
affect our business and results of operations.
 
 
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.
 
In 2017 and 2018, cities, counties, and
 
a state government in California, New
 
York, Washington,
Rhode Island and Maryland, as well as the Pacific
 
Coast Federation of Fishermen’s Association, Inc., filed
lawsuits against oil and gas companies, including
 
ConocoPhillips, seeking compensatory damages
 
and
equitable relief to abate alleged climate change impacts.
 
ConocoPhillips is vigorously defending against
 
these
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.
 
 
25
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, governments have imposed
 
or proposed 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.
 
 
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 for many decades,
 
a number of new laws, regulations and permitting
requirements are under consideration by the
 
U.S. EPA and others which could result in increased costs,
operating restrictions, operational delays or limit
 
the ability to develop oil and natural gas resources.
 
Certain
jurisdictions in which we operate, including state
 
and local governments in Colorado, have adopted
 
or are
considering regulations that could impose new
 
or more stringent permitting, disclosure
 
or other regulatory
requirements on hydraulic fracturing or other oil
 
and natural-gas operations, including subsurface
 
water
disposal.
 
In addition, certain interest groups have also
 
proposed ballot initiatives and constitutional
amendments designed to restrict oil and natural-gas
 
development generally and hydraulic fracturing
 
in
particular.
 
For example, in 2018, Colorado voters rejected
 
Proposition 112, a Colorado ballot initiative that
would have drastically limited the use of hydraulic
 
fracturing in Colorado.
 
In the event that ballot initiatives,
local or state restrictions or prohibitions are
 
adopted and result in more stringent limitations
 
on the production
and development of oil and natural gas in areas
 
where we conduct operations, we may incur significant
 
costs to
comply with such requirements or may experience
 
delays or curtailment in the permitting
 
or pursuit of
exploration, development or production activities.
 
Such compliance costs and delays, curtailments,
 
limitations
or prohibitions could have a material adverse
 
effect on our business, prospects, results of operations, financial
condition and liquidity.
 
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 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.
 
 
Local political and economic factors in international
 
markets could have a material adverse effect on us.
 
Approximately 50 percent of our hydrocarbon
 
production was derived from production outside
 
the U.S. in
2019, and 39 percent of our proved reserves, as
 
of December 31, 2019, 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 effect of international trade discussion and disputes),
changing political 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.
 
 
 
26
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 above, 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
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.
 
We may not be able to successfully complete any disposition we elect to pursue.
 
From time to time, we may seek to divest portions
 
of our business or investments that
 
are not important to our
ongoing strategic objectives.
 
Any dispositions we undertake may involve numerous
 
risks and uncertainties,
any of which could adversely affect our results of operations
 
or financial condition.
 
In particular, we may not
be able to successfully complete any disposition
 
on a timeline or on terms acceptable
 
to us, if at all, whether
due to market conditions, regulatory challenges
 
or other concerns.
 
In addition, the reinvestment of capital
from disposition proceeds may not ultimately
 
yield investment returns in line with our internal
 
or external
expectations.
 
Any dispositions we pursue may also result in
 
disruption to other parts of our business,
including through the diversion of resources
 
and management attention from our ongoing
 
business and other
strategic matters, or through the disruption
 
of relationships with our employees and key
 
vendors.
 
Further, in
connection with any disposition, we may enter into
 
transition services agreements or undertake
 
indemnity or
other obligations that may result in additional
 
expenses for us.
 
We may also be required under applicable
accounting rules to recognize impairments
 
associated with any disposition we pursue,
 
whether or not
completed.
 
As part of our disposition strategy, 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.
 
We may not be able
to liquidate the shares issued to us by Cenovus
 
Energy at prices we deem acceptable, or at all.
 
27
 
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.
 
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.
 
 
 
 
 
28
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
 
for
this reporting period.
 
The following proceedings include those
 
matters that arose during the fourth quarter of
2019, as well as matters previously reported in our
 
2018 Form 10-K and our first-, second- and third-quarter
2019 Form 10-Qs that were not resolved prior
 
to the fourth quarter of 2019.
 
Material developments to the
previously reported matters have been included
 
in the descriptions below.
 
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
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.
 
Matters Previously Reported—ConocoPhillips
On June 28, 2018, the Texas Commission on Environmental Quality issued a Proposed
 
Agreed Order to
ConocoPhillips Company to resolve alleged violations
 
of the Texas Health & Safety Code and/or Commission
Rules occurring in 2015 through 2017 at a formerly
 
owned gas injection plant in Howard
 
County, Texas.
 
In
November of 2019, the company concluded
 
this matter by entering into an Agreed Order
 
with the agency and
paying an administrative penalty of $120,014.
 
 
 
Item 4.
 
MINE SAFETY DISCLOSURES
 
 
Not applicable.
 
 
 
 
 
29
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
 
 
Name
Position Held
Age*
Catherine A. Brooks
Vice President and Controller
54
William L. Bullock, Jr.
President, Asia Pacific & Middle East
55
Ellen R. DeSanctis
Senior Vice President, Corporate Relations
63
Matt J. Fox
Executive Vice President and Chief Operating Officer
59
Michael D. Hatfield
President, Alaska, Canada and Europe
53
Ryan M. Lance
Chairman of the Board of Directors and Chief Executive
 
Officer
57
Andrew D. Lundquist
Senior Vice President, Government Affairs
59
Dominic E. Macklon
President, Lower 48
50
Kelly B. Rose
Senior Vice President, Legal, General Counsel and Corporate Secretary
53
Don E. Wallette, Jr.
Executive Vice President and Chief Financial Officer
61
 
*On February 15, 2020.
 
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 12, 2020.
 
Set forth below is information about the executive
 
officers.
 
Catherine A. Brooks
was appointed Vice President and Controller as of January 1, 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 President, Asia Pacific & Middle
 
East as of April 1, 2015, having
previously served as Vice President, Corporate Planning & Development
 
since May 2012.
 
 
Ellen R. DeSanctis
 
was appointed Senior Vice President, Corporate Relations as of January 1,
 
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 1,
 
2019,
having previously served as Executive Vice President, Strategy, Exploration and Technology since April 2016
and Executive Vice President, Exploration and Production, from 2012 to
 
2016.
 
Prior to that, he was employed
by Nexen, Inc., where he served as Executive
 
Vice President, International since 2010.
 
 
Michael D. Hatfield
 
was appointed President, Alaska, Canada and Europe
 
as of June 3, 2018, having
previously served as President, Canada since
 
October 2016.
 
Prior to that, he served as Vice President, Health,
Safety and Environment from December 2015
 
to October 2016.
 
Mr. Hatfield became Vice President, Cost
Optimization in March 2015 and served in that
 
role until December 2015.
 
Mr. Hatfield previously held the
position of Vice President, Rockies Business Unit from March 2013 to March
 
2015.
 
 
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.
 
 
Andrew D. Lundquist
was appointed Senior Vice President,
 
Government Affairs in 2013.
 
Prior to that, he
served as managing partner of BlueWater Strategies LLC, since 2002.
 
 
 
30
Dominic E. Macklon
 
was appointed President, Lower 48 as of June
 
1, 2018, having previously served as Vice
President, Corporate Planning & Development since
 
January 2017.
 
Prior to that, he served as President, U.K.
from September 2015 to January 2017.
 
Mr. Macklon previously served as Senior Vice President, Oil Sands
from July 2012 to September 2015.
 
 
Kelly B. Rose
was appointed Senior Vice President, Legal, General Counsel and Corporate
 
Secretary 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.
 
 
Don E. Wallette, Jr.
 
was appointed Executive Vice President and Chief Financial Officer on January
 
1, 2019,
having previously served as Executive Vice President, Finance, Commercial
 
and Chief Financial Officer since
April 2016 and as Executive Vice President, Commercial, Business Development
 
and Corporate Planning
from 2012 to 2016.
 
Prior to that, he served as President, Asia Pacific
 
from 2010 to 2012 and President,
Russia/Caspian from 2006 to 2010.
 
 
 
 
 
 
 
 
 
31
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
2019
2018
First
$
0.305
0.285
Second
0.305
0.285
Third
0.305
0.285
Fourth
0.420
0.305
Number of Stockholders of Record at January
 
31, 2020*
41,821
*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.
 
On February 1, 2018, we announced that our Board
 
of Directors approved an increase in the
 
quarterly dividend
to $0.285 per share, compared with the previous
 
quarterly dividend of $0.265 per share.
 
 
On October 5, 2018, we announced that our Board
 
of Directors approved an increase in the
 
quarterly dividend
to $0.305 per share, compared with the previous
 
quarterly dividend of $0.285 per share.
 
 
On October 7, 2019, we announced that our Board
 
of Directors approved an increase in the quarterly
 
dividend
to $0.42 per share, compared with the previous
 
quarterly dividend of $0.305 per share.
 
 
 
 
 
 
 
 
 
 
 
 
32
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, 2019
4,844,970
$
55.54
4,844,970
$
5,855
November 1-30, 2019
4,020,276
58.20
4,020,276
5,621
December 1-31, 2019
3,943,490
62.31
3,943,490
5,375
12,808,736
$
58.46
12,808,736
*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.
 
As of December 31, 2019, we had announced
 
a total authorization to repurchase $15 billion
 
of our common stock.
 
We repurchased $3 billion in 2017, $3
billion in 2018 and $3.5 billion in 2019.
 
Of the remaining authorization, we expect to
 
repurchase $3 billion in
2020.
 
In February 2020, we announced that the
 
Board of Directors approved an increase
 
to our repurchase
authorization from $15 billion to $25 billion,
 
to support our plan for future share repurchases.
 
Acquisitions for
the share repurchase program 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 Risk Factors “Our ability to declare
 
and pay dividends and repurchase
shares is subject to certain considerations.”
cop-20191231p35i0.jpg
 
33
Stock Performance Graph
 
The following graph shows the cumulative total
 
shareholder return (TSR) for ConocoPhillips’
 
common stock
in each of the five years from December 31, 2014,
 
to December 31, 2019.
 
The graph also compares the
cumulative total returns for the same five-year period
 
with the S&P 500 Index, the performance peer
 
group
used in the prior fiscal year (the “Prior Peer
 
Group”) and a new performance peer group for
 
the current fiscal
year (the “New Peer Group”).
 
The Prior Peer Group consists of BP, Chevron, ExxonMobil, Royal Dutch
Shell, Total, Apache, Devon, Marathon Oil Corporation and Occidental,
 
weighted according to the respective
peer’s stock market capitalization at the beginning
 
of each annual period.
 
For the purpose of aligning to
performance peers with similar complexities
 
and portfolios, the New Peer Group excludes
 
BP,
 
Royal Dutch
Shell, and Total, and includes Noble Energy, Hess, and EOG Resources.
 
For the 2018 Stock Performance
Graph, Anadarko was also presented within
 
the Prior Peer Group.
 
However, due to Anadarko’s acquisition by
Occidental completed in 2019, Anadarko’s performance has been excluded
 
from all five years of the Prior Peer
Group performance.
 
The comparison assumes $100 was invested
 
on December 31, 2014, in ConocoPhillips
stock, the S&P 500 Index and ConocoPhillips’
 
peer groups
 
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.
 
 
 
*Prior Peer Group: BP; Chevron; ExxonMobil; Royal Dutch Shell; Total; Apache; Devon, Marathon Oil Corporation; Occidental.
**New Peer Group: Chevron; ExxonMobil; Apache; Devon; EOG Resources; Hess; Marathon Oil Corporation;
 
Noble Energy; Occidental.
 
 
 
 
 
 
 
 
 
 
 
 
 
34
Item 6.
 
SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts
2019
2018
2017
2016
2015
Sales and other operating revenues
$
32,567
36,417
29,106
23,693
29,564
Net income (loss)
7,257
6,305
(793)
(3,559)
(4,371)
Net income (loss) attributable to
ConocoPhillips
7,189
6,257
(855)
(3,615)
(4,428)
Per common share
Basic
6.43
5.36
(0.70)
(2.91)
(3.58)
Diluted
6.40
5.32
(0.70)
(2.91)
(3.58)
Total assets
70,514
69,980
73,362
89,772
97,484
Long-term debt
14,790
14,856
17,128
26,186
23,453
Cash dividends declared per common share
1.34
1.16
1.06
1.00
2.94
 
 
In 2019, we disposed of two ConocoPhillips U.K. subsidiaries
 
for proceeds of $2.2 billion after interest and
customary adjustments.
 
In 2017, we disposed of assets for consideration
 
of approximately $16 billion including
 
our 50 percent
nonoperated interest in the FCCL Partnership,
 
as well as the majority of our western Canada gas
 
assets, and
our interests in the San Juan Basin.
 
 
These factors
 
impact the comparability of historical
 
information.
 
 
See Management’s Discussion and Analysis of Financial Condition and
 
Results of Operations and the Notes to
Consolidated Financial Statements for a discussion
 
of factors that will enhance an understanding
 
of this data.
 
35
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,” “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 of the forward-looking information unless required to do so under the federal securities
laws.
 
Readers are cautioned that such forward-looking statements should be read in conjunction with
 
the
company’s
 
disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE
‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,”
beginning on page
 
 
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
 
 
BUSINESS ENVIRONMENT AND EXECUTIVE
 
OVERVIEW
 
 
ConocoPhillips is an independent E&P company
 
with operations and activities in 17 countries.
 
Our diverse,
low cost of supply portfolio includes resource-rich
 
unconventional plays in North America;
 
conventional
assets in North America, Europe, Asia and
 
Australia; LNG developments; oil sands in
 
Canada; and an
inventory of global conventional and unconventional
 
exploration prospects.
 
Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately
 
10,400 people worldwide and had total
 
assets of
 
$71 billion.
 
 
Overview
 
Global oil prices continued
 
to be volatile in 2019.
 
Optimism about worldwide economic growth during
 
the
first quarter turned to pessimism in the second quarter
 
as trade disputes dampened growth forecasts.
 
At the
end of the second quarter, geopolitical tensions in the Middle East,
 
threatening the safe passage of supertankers
carrying crude oil through the Persian Gulf, revived
 
oil prices.
 
Worldwide economic growth concerns returned
in the third quarter to depress prices, only to be
 
reversed again by geopolitical tensions in the
 
Middle East, as
oilfield infrastructure in Saudi Arabia was attacked,
 
temporarily disrupting approximately
 
five percent of the
world’s oil supply.
 
Production was restored relatively quickly, and prices settled in the fourth
 
quarter.
 
Brent
crude averaged $64
 
per barrel in 2019, down nine percent
 
from the prior year.
 
Our business strategy
anticipates prices will remain volatile and is designed
 
to be resilient in lower price environments, while
retaining upside during periods of higher prices.
 
Portfolio diversification and optimization, a strong
 
balance
sheet and disciplined capital investment have positioned
 
our company to navigate through volatile energy
cycles.
 
Our value proposition principles, namely, to focus on financial returns, maintain
 
a strong balance sheet, deliver
compelling returns of capital,
 
and expand cash flow through disciplined capital
 
investments, are being
executed in accordance with our priorities for
 
allocating cash flows from the business.
 
These priorities are:
invest capital to sustain
 
production and pay our existing dividend;
 
grow our existing dividend; maintain debt at
a level we believe is sufficient to maintain a strong investment
 
grade credit rating through price cycles; allocate
greater than 30 percent of our net cash provided
 
by operating activities to share repurchases
 
and dividends;
and, invest capital in a disciplined fashion to grow
 
our cash from operations.
 
We believe our commitment to
our value proposition, as evidenced by the results
 
discussed below, positions us for success in an environment
of price uncertainty and ongoing volatility.
 
 
36
 
In 2019, we successfully delivered on our priorities.
 
We achieved production growth of five percent on a total
BOE basis compared with the prior year, with higher value oil
 
volumes growing eight percent.
 
Cash provided
by operating activities of $11.1 billion exceeded capital expenditures
 
and
 
investments of $6.6 billion.
 
After
repurchasing $3.5 billion of our common stock
 
and paying $1.5 billion of dividends to shareholders,
 
we ended
the year with cash, cash equivalents and restricted
 
cash totaling $5.4 billion and $3.0 billion
 
of short-term
investments.
 
In October, we announced an increase to our quarterly dividend
 
of 38 percent to $0.42 per share
and announced planned 2020 share buybacks of
 
$3 billion.
 
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
The plan includes
funding for ongoing development drilling
 
programs, major projects, exploration and appraisal
 
activities, as
well as base maintenance.
 
Capital spend is expected to be higher in the first
 
quarter largely from winter
construction and exploration and appraisal drilling
 
in Alaska.
 
This guidance does not include capital for
acquisitions.
 
Key Operating and Financial Summary
 
Significant items
 
during 2019 included the following:
 
 
Net cash provided by operating activities was $11.1 billion and exceeded capital
 
expenditures and
investments of $6.6 billion.
 
 
Repurchased $3.5 billion of shares and paid $1.5 billion in dividends,
 
representing 45 percent of net cash
provided by operating activities.
 
Increased the quarterly dividend by 38 percent to $0.42 per share
 
.
 
Achieved 100 percent total reserve replacement and 117
 
percent organic replacement.
 
Underlying production, which excludes Libya and the net volume impact
 
from closed dispositions and
acquisitions of 51 MBOED in 2019 and 47 MBOED in 2018, grew 5 percent
 
.
 
Increased production from the Lower 48 Big 3 unconventionals—Eagle
 
Ford, Bakken and Permian
Unconventional—by 22 percent year-over-year.
 
Executed successful Alaska appraisal program; conducted appraisal drilling
 
and commissioned
infrastructure at Montney in Canada.
 
Completed Lower 48, Alaska and Argentina acquisitions;
 
awarded a 20-year extension of the Indonesia
Corridor Block PSC, with new terms.
 
Generated $3 billion in disposition proceeds; entered into agreements to
 
sell Australia-West
 
assets for $1.4
billion and Niobrara for $0.4 billion, both subject to customary closing
 
adjustments, as well as regulatory
and other approvals.
 
Reduced asset retirement obligations and accrued environmental costs by $2.3
 
billion, primarily due to
closed and pending dispositions.
 
 
Ended the year with cash, cash equivalents and restricted cash totaling $
 
5.4 billion and short-term
investments of $3.0 billion.
 
Recognized a $296 million after-tax impairment related
 
to the sale of our Niobrara interests in the Lower
48 segment.
 
Discontinued exploration activities in the Central Louisiana Austin Chalk trend
 
and recognized $197
million after-tax in leasehold impairment and dry hole expenses.
 
 
Operationally, we remain focused on safely executing our operating plan and maintaining
 
capital and cost
discipline.
 
Production of 1,348 MBOED increased 5 percent
 
or 65 MBOED in 2019 compared with 2018.
 
Production, excluding Libya, of 1,305 MBOED
 
increased 5 percent or 63 MBOED.
 
Underlying production,
which excludes Libya and the net volume impact
 
from closed dispositions and acquisitions
 
of 51 MBOED in
2019 and 47 MBOED in 2018, is used to measure
 
our ability to grow production organically.
 
Our underlying
production grew 5 percent in 2019 to 1,254 MBOED
 
from 1,195 MBOED in 2018.
 
 
On September 30, 2019, we completed the sale of
 
two ConocoPhillips U.K. subsidiaries to
 
Chrysaor E&P
Limited for proceeds of $2.2 billion after interest
 
and customary adjustments.
 
In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax
 
gain associated with this transaction.
 
Together the subsidiaries
 
 
 
37
sold our indirectly held exploration and production
 
assets in the U.K., including $1.8 billion
 
of ARO.
 
Annualized average production associated with the
 
U.K. assets sold was 50 MBOED in 2019.
 
Reserves
associated with the U.K. assets sold were 84 MMBOE
 
at the time of disposition.
 
Results of operations for the
U.K. are reported within our Europe and North
 
Africa segment.
 
In the second quarter of 2019, we completed the sale
 
of our 30 percent interest in the Greater Sunrise
 
Fields to
the government of Timor-Leste for $350 million and recognized
 
an after-tax gain of $52 million.
 
No
production or reserve impacts were associated
 
with the sale.
 
The Greater Sunrise Fields were included in
 
our
Asia Pacific and Middle East segment.
 
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary
 
adjustments, with an effective date of January 1, 2019.
 
In addition, we will receive a payment of $75 million
 
upon final investment decision of the Barossa
development project.
 
These subsidiaries hold our 37.5 percent interest
 
in the Barossa Project and Caldita
Field, our 56.9 percent interest in the Darwin LNG
 
Facility and Bayu-Undan Field, our 40 percent
 
interest in
the Greater Poseidon Fields, and our 50 percent
 
interest in the Athena Field.
 
This transaction is expected to be
completed in the first quarter of 2020, subject to regulatory
 
approvals and the satisfaction of other specific
conditions precedent.
 
In 2019, production associated with the Australia-West assets to be sold was 48
MBOED.
 
Year
 
-end 2019
 
reserves associated with these assets were 17
 
MMBOE.
 
We will retain our 37.5
percent interest in the Australia Pacific LNG project
 
and operatorship of that project’s LNG facility.
 
Results
of operations for the subsidiaries to be sold are reported
 
within our Asia Pacific and Middle East segment.
 
In the fourth quarter of 2019, we signed an agreement
 
to sell our interests in the Niobrara shale play
 
for $380
million, plus customary adjustments,
 
and overriding royalty interests in certain
 
future wells.
 
We recorded an
after-tax impairment
 
of $296 million in the fourth quarter of 2019 to reduce
 
the carrying value to fair value.
 
In
2019, production from Niobrara was 11 MBOED.
 
Year
 
-end 2019 reserves associated with the
 
Niobrara assets
to be sold were 14 MMBOE.
 
This transaction is subject to regulatory approval
 
and other conditions precedent
and is expected to close in the first quarter
 
of 2020.
 
The Niobrara results of operations are reported
 
within our
Lower 48 segment.
 
For more information regarding the accounting impacts
 
of these transactions, see Note 5—Asset Acquisitions
and Dispositions,
 
in the Notes to Consolidated Financial
 
Statements.
 
Business Environment
 
Brent crude oil prices averaged $64 per barrel in 2019,
 
ranging from a low of $53 per barrel in January
 
to a
high of almost $75 per barrel in April.
 
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;
 
focus on financial returns through cash flow
expansion, maintain balance sheet strength and
 
deliver peer-leading distributions.
 
Operational and Financial Factors Affecting
 
Profitability
The focus areas we believe will drive our success
 
through the price cycles include:
 
 
Maintain a relentless focus on safety and environmental
 
stewardship.
 
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, on November 2017,
we announced our intention to target a 5 to 15 percent reduction
 
in our GHG emission
 
intensity by 2030.
 
In December 2018, we became a founding
 
member of the Climate Leadership
Council (CLC), an international policy institute
 
founded in collaboration with business and
 
 
 
 
 
38
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.
 
In early 2019, we issued our first stand-alone
 
Climate-related Risk
Report and incorporated this into our website
 
during our annual Sustainability Report update.
 
Our
sustainability efforts continued through 2019 with a focus
 
on advancing our action plans for climate
change, biodiversity, water and human rights.
 
We are committed to building a learning organization
using human performance principles as we relentlessly
 
pursue improved HSE and operational
performance.
 
 
Focus on financial returns.
 
This is a core principle of our value proposition.
 
Our goal is to achieve
strong financial returns by exercising capital
 
discipline,
 
controlling our costs, and continually
optimizing our portfolio.
 
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 should
 
lead to value maximization and cash flow
expansion using an optimized investment pace,
 
not production growth for growth’s sake.
 
Additional capital may be allocated toward growth,
 
but discipline will be maintained.
 
Our
cash allocation priorities call for the investment
 
of sufficient capital to sustain production and
pay the existing dividend.
 
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
The plan includes funding for ongoing development
 
drilling programs, major projects,
exploration and appraisal activities, as
 
well as base maintenance.
 
Capital spend is expected to
be higher in the first quarter largely from winter construction
 
and exploration and appraisal
drilling in Alaska.
 
This guidance does not include capital
 
for acquisitions.
 
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 2019, our production and operating expenses
 
were
two percent higher than 2018, primarily due to costs
 
associated with higher production
volumes, which grew five percent during the same
 
period.
 
o
 
Optimize our portfolio.
 
We continue to optimize our asset portfolio to focus on low cost of
supply assets that support our strategy.
 
In 2019, we continued to dispose of or market
 
certain
non-core assets, including the U.K., Australia-West and our Niobrara assets
 
in the Lower 48.
 
Additions to the portfolio were made in the Lower
 
48 with bolt-on interests and acreage
acquisitions,
 
in Alaska with the Nuna discovery acreage acquisition,
 
and internationally with
entrance into Argentina’s Neuquén and Austral Basins.
 
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.
 
 
 
 
 
 
39
 
Maintain balance sheet strength.
 
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 repurchasing shares on a dollar cost
 
average basis.
 
 
Return value to shareholders.
 
We believe in delivering value to our shareholders via a growing,
sustainable dividend supplemented by share repurchases.
 
In 2019, we paid dividends on our common
stock of approximately $1.5 billion and repurchased
 
$3.5 billion of our common stock.
 
Combined,
our dividend and repurchases represented 45 percent
 
of our net cash provided by operating
 
activities.
 
Since we initiated our current share repurchase
 
program in late 2016, we have repurchased $9.6
 
billion
of shares.
 
Additionally, as of December 31, 2019, $5.4 billion of repurchase authority
 
remained of the
$15 billion share repurchase program our Board
 
of Directors had authorized.
 
In February 2020, we
announced that the Board of Directors approved
 
an increase to our repurchase authorization
 
from $15
billion to $25 billion, to support our plan for future
 
share repurchases.
 
Whether we undertake these
additional repurchases is ultimately subject to numerous
 
considerations, including market conditions
and other factors.
 
See Risk Factors “Our ability to declare and
 
pay dividends and repurchase shares is
subject to certain considerations.”
 
In October 2019, we announced that our Board
 
of Directors approved an increase to our quarterly
dividend of 38 percent to $0.42 per share.
 
 
Add to our proved reserve base.
 
We primarily add to our proved reserve base in three ways:
 
o
 
Successful exploration, exploitation and development
 
of new and existing fields.
o
 
Application of new technologies and processes
 
to improve recovery from existing fields.
o
 
Purchases of increased interests in existing
 
fields and bolt-on acquisitions.
 
Proved reserve estimates require economic production
 
based on historical 12-month, first-of-month,
average prices and current costs.
 
Therefore, 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.
 
In 2019, our reserve replacement, which included
 
a net decrease of 0.1 billion BOE from
sales and purchases, was 100 percent.
 
Increased crude oil reserves accounted for approximately
 
55
percent of the total change in reserves. Our organic reserve
 
replacement, which excludes the impact of
sales and purchases, was 117 percent in 2019.
 
Approximately 50 percent of organic reserve additions
were from Lower 48 unconventional assets.
 
The remaining additions were evenly distributed
 
across
the other operating segments.
 
In the five years ended December 31, 2019, our reserve
 
replacement was negative 34 percent,
reflecting the impact of asset dispositions and lower
 
prices during that period.
 
Our organic reserve
replacement during the five years ended December
 
31, 2019, which excludes a decrease of 2.0 billion
BOE related to sales and purchases, was 40 percent,
 
reflecting development activities as
 
well as lower
prices during that period.
 
Historically, our reserve replacement has varied considerably year to year contingent
 
upon the timing
of major projects which may have long lead times
 
between capital investment and production.
 
In the
last several years, more of our capital has been
 
allocated to short cycle time, onshore,
 
unconventional
plays.
 
Accordingly, we believe our recent success in replacing reserves can be viewed
 
on a trailing
three-year basis.
 
 
In the three years ended December 31, 2019, our reserve
 
replacement was 23 percent, reflecting the
impact of asset dispositions during that period.
 
Our organic reserve replacement during the three
years ended December 31, 2019, which excludes a
 
decrease of 1.8 billion BOE related to sales
 
and
purchases, was 143 percent, reflecting reserve
 
additions from development activities.
 
 
 
 
 
cop-20191231p42i0.jpg
 
40
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.
 
 
 
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 evaluate potential
 
solutions 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 seismic
 
advancements.
 
 
Attract, develop and retain a talented work force.
 
We strive to attract, develop and retain individuals
with the knowledge and skills to implement
 
our business strategy and who support our 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,
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:
 
 
 
 
 
 
 
41
Brent crude oil prices averaged $64.30 per barrel
 
in 2019, a decrease of 9 percent compared
 
with
$71.04 per barrel in 2018.
 
Similarly, WTI crude oil prices decreased 12 percent from $64.92 per
barrel in 2018 to $57.02 per barrel in 2019.
 
Crude oil prices weakened year over year primarily
 
due to
ample global supplies and a decelerating global
 
economy.
 
Henry Hub natural gas price averages decreased
 
15 percent from $3.09 per MMBTU in 2018 to
 
$2.63
per MMBTU in 2019.
 
Natural gas prices weakened in 2019 versus the
 
prior year due to strong
production, while demand growth was dampened
 
by mild weather.
 
Our realized NGL prices decreased 34 percent from
 
$30.48 per barrel in 2018 to $20.09 per barrel
 
in
2019.
 
NGL prices weakened year over year due to
 
strong supply growth with only moderate demand
growth.
 
Our realized bitumen price increased 42 percent
 
from $22.29 per barrel in 2018 to $31.72 per
 
barrel in
2019.
 
Curtailment orders imposed by the Alberta
 
Government, which limited production from
 
the
province starting January 2019, provided strength
 
to the WCS differential to WTI at Hardisty.
 
We
continue to optimize bitumen price realizations
 
through the utilization of downstream transportation
solutions and implementation of alternate blend capability
 
which results in lower diluent costs.
 
Our worldwide annual average realized price decreased
 
9 percent from $53.88
 
per BOE in 2018 to
$48.78
 
per BOE in 2019 due to lower realized oil,
 
natural gas and NGL 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.
 
A sustained decline in the current and long-term
outlook on gas price could affect the carrying value
 
of certain Lower 48 non-core gas assets and it
 
is
reasonably possible this could result in a future
 
non-cash impairment.
 
For additional information on
our impairments in 2019, 2018 and 2017, see
 
Note 9—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
 
42
increase government fiscal take could have a
 
negative impact on future operations.
 
Our management
carefully considers the fiscal and regulatory
 
environment when evaluating projects or
 
determining the
levels and locations of our activity.
 
 
Outlook
 
Full-year 2020 production is expected to be 1,230
 
MBOED to 1,270 MBOED, including the impact
 
of a recent
third-party pipeline outage on the Kebabangan
 
Field in Malaysia.
 
First-quarter 2020 production is expected to
be 1,240 MBOED to 1,280 MBOED.
 
Production guidance for 2020 excludes Libya.
 
Operating Segments
 
We manage our operations through six operating segments, which are primarily
 
defined by geographic region:
Alaska, Lower 48, Canada, Europe and North
 
Africa, Asia Pacific and Middle East, and Other
 
International.
 
Corporate and Other represents 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.
 
 
 
 
 
 
 
 
 
 
43
RESULTS OF OPERATIONS
This section of the Form 10-K
 
discusses year-to-year comparisons between 2019
 
and 2018.
 
For discussion of
year-to-year comparisons between 2018 and 2017, see
 
"Management's Discussion and Analysis
 
of Financial
Condition and Results of Operations" in Part II, Item
 
7 of our 2018 10-K.
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips
 
by business segment follows:
Millions of Dollars
Years Ended December 31
2019
2018
2017
Alaska
$
1,520
1,814
1,466
Lower 48
436
1,747
(2,371)
Canada
279
63
2,564
Europe and North Africa
2,724
1,866
553
Asia Pacific and Middle East
1,929
2,070
(1,098)
Other International
263
364
167
Corporate and Other
38
(1,667)
(2,136)
Net income (loss) attributable to ConocoPhillips
$
7,189
6,257
(855)
 
 
2019 vs. 2018
 
Net income attributable to ConocoPhillips
 
increased $932 million in 2019.
 
The increase was mainly due to:
 
 
A $2.1 billion after-tax gain associated with the
 
completion of the sale of two ConocoPhillips
 
U.K.
subsidiaries to Chrysaor E&P Limited.
 
 
An unrealized gain of $649 million after-tax
 
on our Cenovus Energy (CVE) common shares in 2019,
as compared to a $436 million after-tax unrealized
 
loss on those shares in 2018.
 
Higher crude oil sales volumes due to growth in the
 
Lower 48 unconventionals and from the
acquisition of incremental interests in operated
 
assets in Alaska during the second and
 
fourth quarters
of 2018.
 
 
The absence of premiums on early debt retirements
 
totaling $195 million after-tax.
 
A $164 million income tax benefit related to
 
deepwater incentive tax credits recognized for
 
Malaysia
Block G.
 
A $151
 
million income tax benefit related to the
 
revaluation of deferred tax assets following
finalization of rules relating to the 2017 Tax Cuts and Jobs Act.
 
These increases in net income were partly offset by:
 
 
Lower realized crude oil, natural gas and NGL
 
prices.
 
The absence of a $774 million after-tax gain on the
 
Clair disposition in the U.K.
 
A $296
 
million after-tax impairment related to
 
the sale of our Lower 48 Niobrara interests.
 
Lower equity in earnings of affiliates due to $120 million
 
of impairments to equity method
investments in our Lower 48 segment and a $118 million reduction
 
in equity earnings at QG3 in our
Asia Pacific and Middle East segment due to a deferred
 
tax adjustment.
 
Higher exploration expenses, primarily in
 
our Lower 48 segment due to $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 trend.
 
 
 
 
 
 
 
 
 
 
 
 
44
 
Income Statement Analysis
 
2019 vs. 2018
 
Sales and other operating revenues decreased 11 percent in 2019,
 
mainly due to lower realized crude oil,
natural gas and NGL prices, partly offset by higher sales
 
volumes of crude oil in the Lower 48 and Alaska.
 
Equity in earnings of affiliates decreased $295 million
 
in 2019, primarily due to impairments of equity
 
method
investments in our Lower 48 segment totaling
 
$155 million.
 
Additionally, equity earnings decreased $118
million resultant from a deferred tax adjustment
 
at QG3,
 
reported in our Asia Pacific and Middle East segment.
 
For more information related to these items,
 
see Note 3—Variable Interest Entities and Note 5—Asset
Acquisitions and Dispositions, in the Notes to
 
Consolidated Financial Statements.
 
Gain on dispositions increased $903 million
 
in 2019, primarily due to a $1.7
 
billion before-tax gain associated
with the completion of the sale of two ConocoPhillips
 
U.K. subsidiaries to Chrysaor E&P Limited.
 
Partly
offsetting this increase, was the absence of a $715 million
 
before-tax gain on the sale of a ConocoPhillips
subsidiary to BP in 2018,
 
which held 16.5 percent of our 24 percent interest
 
in the BP-operated Clair Field in
the U.K.
 
For additional information related to these dispositions,
 
see Note 5—Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial
 
Statements.
 
Other income increased $1,185 million in 2019, primarily
 
due to an unrealized gain of $649 million before-tax
on our CVE common shares in 2019, and the absence
 
of a $437 million before-tax unrealized loss
 
on those
shares in 2018.
 
For discussion of our CVE shares, see Note
 
7—Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements.
 
Purchased commodities decreased 17 percent in
 
2019, primarily due to lower natural gas
 
and crude oil prices.
 
Selling, general and administrative expenses increased
 
$155 million in 2019, primarily due to higher
 
costs
associated with compensation and benefits,
 
including mark to market impacts of certain
 
key employee
compensation programs, and increased facility
 
costs.
 
Exploration expenses increased $374 million
 
in 2019, primarily due to higher leasehold impairment
 
and dry
hole costs,
 
mainly in our Lower 48 segment,
 
and higher exploration G&A expenses.
 
In 2019, we recorded a
$141 million before-tax leasehold impairment
 
expense due to our decision to discontinue
 
exploration activities
in the Central Louisiana Austin Chalk trend and
 
expensed $111 million of dry hole costs related to this play.
 
 
Impairments increased $378 million in
 
2019, mainly due to a $379 million before-tax impairment
 
related to the
sale of our Niobrara interests in the Lower 48 segment.
 
For additional information, see Note 5—Asset
Acquisitions and Dispositions and Note 9—Impairments,
 
in the Notes to Consolidated Financial Statements.
 
 
Other expenses decreased $310 million in
 
2019, primarily due to the absence of a $206
 
million before-tax
expense for premiums on early debt retirements
 
and lower pension settlement expense.
 
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements,
 
for information regarding our
income tax provision (benefit) and effective tax rate.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
45
Summary Operating Statistics
2019
2018
2017
Average Net Production
Crude oil (MBD)
705
653
599
Natural gas liquids (MBD)
115
102
111
Bitumen (MBD)
60
66
122
Natural gas (MMCFD)
2,805
2,774
3,270
Total Production
 
(MBOED)
1,348
1,283
1,377
Dollars Per Unit
Average Sales Prices
 
Crude oil (per bbl)
$
60.99
68.13
51.96
Natural gas liquids (per bbl)
20.09
30.48
25.22
Bitumen (per bbl)
31.72
22.29
22.66
Natural gas (per mcf)
5.03
5.65
4.07
Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other
$
322
274
368
Leasehold impairment
221
56
136
Dry holes
200
39
430
$
743
369
934
 
 
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on
 
a worldwide
basis.
 
At December 31, 2019, our operations were
 
producing in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, China, Malaysia, Qatar and
 
Libya.
 
2019 vs. 2018
 
Total production, including Libya, of 1,348 MBOED increased 65 MBOED
 
or 5 percent in 2019 compared
with 2018,
 
primarily due to:
 
 
New wells online in the Lower 48.
 
An increased interest in the Western North Slope (WNS) and Greater Kuparuk Area
 
(GKA) of Alaska
following acquisitions closed in 2018.
 
 
Higher production in Norway due to drilling activity
 
and the startup of Aasta Hansteen in December
2018.
 
 
The increase in production during 2019 was
 
partly offset by:
 
 
Normal field decline.
 
Disposition impacts from the U.K. and non-core
 
asset sales in the Lower 48.
 
Production excluding Libya was 1,305 MBOED in
 
2019 compared with 1,242 MBOED in 2018,
 
an increase of
63 MBOED or 5 percent.
 
Underlying production, which excludes Libya and
 
the net volume impact from
closed dispositions and acquisitions of 51 MBOED
 
in 2019 and 47 MBOED in 2018, is used to measure
 
our
ability to grow production organically.
 
Our underlying production grew 5 percent to 1,254
 
MBOED in 2019
from 1,195 MBOED in 2018.
 
 
 
 
 
 
 
 
 
 
 
 
 
46
Alaska
2019
2018
2017
Net Income Attributable to ConocoPhillips
 
(millions of dollars)
$
1,520
1,814
1,466
Average Net Production
Crude oil (MBD)
202
171
167
Natural gas liquids (MBD)
15
14
14
Natural gas (MMCFD)
7
6
7
Total Production
 
(MBOED)
218
186
182
Average Sales Prices
 
Crude oil (per bbl)
$
64.12
70.86
53.33
Natural gas (per mcf)
3.19
2.48
2.72
 
 
The Alaska segment primarily explores for, produces, transports
 
and markets crude oil, NGLs and natural gas.
 
In 2019, Alaska contributed 25 percent of our
 
worldwide liquids production and less than 1 percent
 
of our
natural gas production.
 
2019 vs. 2018
 
Alaska reported earnings of $1,520 million in
 
2019, compared with earnings of $1,814 million
 
in 2018.
 
The
decrease in earnings was mainly due to lower
 
realized crude oil prices and higher production
 
and operating and
DD&A expenses associated with incremental volumes
 
from acquisitions completed during 2018.
 
Additionally, earnings were lower due to the absence of a $98 million tax valuation
 
allowance reduction,
 
the
absence of a $79 million after-tax benefit resulting
 
from an accrual reduction due to a transportation
 
cost ruling
by the FERC,
 
and $62 million less in enhanced oil recovery
 
credits.
 
Partly offsetting these decreases in
earnings, were higher crude oil sales volumes
 
due to the GKA and WNS acquisitions completed
 
in 2018.
 
Average production increased 32 MBOED in 2019 compared with 2018, primarily
 
due to acquisitions at GKA
and WNS in 2018, which provided an incremental
 
38 MBOED of production in 2019, as well as volumes
 
from
new wells online.
 
These production increases were partly offset by normal
 
field decline.
 
Acquisition Update
In the third quarter of 2019, we completed the
 
Nuna discovery acreage acquisition for approximately
 
$100
million, expanding the Kuparuk River Unit by
 
21,000 acres and leveraging legacy infrastructure.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
47
Lower 48
2019
2018
2017
Net Income (Loss) Attributable to ConocoPhillips
 
(millions of dollars)
$
436
1,747
(2,371)
Average Net Production
Crude oil (MBD)
266
229
180
Natural gas liquids (MBD)
81
69
69
Natural gas (MMCFD)
622
596
898
Total Production
 
(MBOED)
451
397
399
Average Sales Prices
 
Crude oil (per bbl)
$
55.30
62.99
47.36
Natural gas liquids (per bbl)
16.83
27.30
22.20
Natural gas (per mcf)
2.12
2.82
2.73
 
 
The Lower 48 segment consists of operations located
 
in the contiguous U.S. and the Gulf of Mexico.
 
During
2019, the Lower 48 contributed 39 percent of our
 
worldwide liquids production and 22 percent
 
of our natural
gas production.
 
 
2019 vs. 2018
 
Lower 48 reported earnings of $436 million in
 
2019, compared with $1,747 million in 2018.
 
Earnings
decreased primarily due to lower realized crude oil,
 
NGL and natural gas prices; higher DD&A due to
increased production volumes; a $301 million after-tax
 
impairment of our Niobrara assets;
 
higher exploration
expenses, primarily due to 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; and
lower earnings in equity
 
affiliates due to a combined $120 million after-tax
 
of impairments associated with a
fair value reduction of our investment in MWCC
 
and the disposition of our interests in the
 
Golden Pass LNG
Terminal and Golden Pass Pipeline.
 
Partly offsetting the decrease in earnings were increased
 
crude oil and
NGL sales volumes in the Eagle Ford, Bakken
 
and Permian Unconventional.
 
For additional information related to our impairment
 
of MWCC, see Note 3—Variable Interest Entities in the
Notes to Consolidated Financial Statements.
 
For more information related to the sale of our interests
 
in
Golden Pass LNG Terminal and Golden Pass Pipeline, see Note 5—Asset
 
Acquisitions and Dispositions in the
Notes to Consolidated Financial Statements.
 
 
Total average production increased 54 MBOED in 2019 compared with 2018.
 
The increase was primarily due
to new production from unconventional assets in
 
Eagle Ford, Bakken and the Permian Basin,
 
partly offset by
normal field decline.
 
Additionally, production decreased by 10 MBOED due to non-core dispositions
 
in 2018.
 
Asset Dispositions
 
Update
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 have also entered into agreements to amend our contractual
obligations for retaining use of the facilities.
 
As a result of entering into these agreements, we recognized
 
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.
 
See Note 15—Fair Value Measurement in the Notes to Consolidated Financial Statements, for
 
additional
information.
 
In the fourth quarter of 2019, we sold our interests
 
in the Magnolia field and platform and recognized
 
an after-
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48
tax gain of $63 million.
 
Production from Magnolia in 2019 was less
 
than one MBOED.
 
 
In the fourth quarter of 2019, we signed an agreement
 
to sell our interests in the Niobrara shale
 
play for $380
million, plus customary adjustments,
 
and overriding royalty interests in certain
 
future wells.
 
We recorded an
after-tax impairment of $301 million in
 
the fourth quarter to reduce the carrying value to
 
fair value.
 
Production from Niobrara was approximately 11 MBOED in 2019.
 
This transaction is subject to regulatory
approval and other conditions precedent and
 
is expected to close in the first quarter
 
of 2020.
 
 
In January 2020, we entered into an agreement to
 
sell our interests in certain non-core properties
 
in the Lower
48 segment for $186 million, plus customary
 
adjustments.
 
The assets met the held for sale criteria
 
in January
2020 and the transaction is expected to be completed
 
in the first quarter of 2020.
 
No gain or loss is anticipated
on the sale.
 
This disposition will not have a significant
 
impact on Lower 48 production.
 
 
For additional information on these transactions,
 
see Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
Canada
2019
2018
2017
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
279
63
2,564
Average Net Production
Crude oil (MBD)
1
1
3
Natural gas liquids (MBD)
-
1
9
Bitumen (MBD)
Consolidated operations
60
66
59
Equity affiliates
-
-
63
Total bitumen
60
66
122
Natural gas (MMCFD)
9
12
187
Total Production
 
(MBOED)
63
70
165
Average Sales Prices
 
Crude oil (per bbl)
$
40.87
48.73
43.69
Natural gas liquids (per bbl)
19.87
43.70
21.51
Bitumen (dollars per bbl)*
Consolidated operations
31.72
22.29
21.43
Equity affiliates
-
-
23.83
Total bitumen
31.72
22.29
22.66
Natural gas (per mcf)
0.49
1.00
1.93
*Average prices for sales of bitumen produced during 2018 and 2019 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 2019, Canada contributed 7 percent of our
 
worldwide
liquids production and less than one percent of
 
our worldwide natural gas production.
 
2019 vs. 2018
 
Canada operations reported earnings of $279 million
 
in 2019 compared with $63 million in 2018.
 
Earnings
increased mainly due to higher realized bitumen
 
prices,
 
a $68 million tax benefit primarily comprised
 
of a
previously unrecognizable tax basis related to
 
a tax settlement,
 
lower DD&A expense due to lower rates from
 
 
 
 
 
 
 
 
 
 
 
 
 
49
reserve additions,
 
lower production and operating expenses,
 
and a $25 million tax benefit due to a four year
phased four percent reduction in Alberta’s corporate income tax rate.
 
Partly offsetting the increase in earnings
were lower sales volumes due to a planned turnaround
 
at Surmont, lower production due to a mandated
production curtailment imposed by the Alberta
 
government in January 2019, and the absence of
 
an $80 million
tax restructuring benefit.
 
Total average production decreased 7 MBOED in 2019 compared with 2018.
 
The production decrease was
primarily due to a turnaround at Surmont, which
 
had an annualized average impact of 3 MBOED,
 
and a
mandated production curtailment imposed by the
 
Alberta government,
 
which also impacted production by 3
MBOED.
 
The curtailment program is established and administered
 
by the Alberta Energy Regulator under the
Curtailment Rules regulation, which is currently
 
set to expire on December 31, 2020.
 
This program is
intended to strengthen the WCS differential to WTI at
 
Hardisty.
 
Asset Disposition
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
was $11.0 billion in cash after customary adjustments, 208 million
 
Cenovus Energy common shares and a five
year uncapped contingent payment.
 
The contingent payment, calculated and paid
 
on a quarterly basis, is $6
million CAD for every $1 CAD by which the WCS
 
quarterly average crude
 
price exceeds $52 CAD per barrel.
 
During 2019 and 2018, we recorded after-tax gains
 
on dispositions for these contingent payments of
 
$84
million and $68 million,
 
respectively.
 
See Note 5—Asset Acquisitions and Dispositions
 
in the Notes to
Consolidated Financial Statements, for additional
 
information.
 
Europe and North Africa
2019
2018
2017
Net Income Attributable to ConocoPhillips
 
(millions of dollars)
$
2,724
1,866
553
Average Net Production
Crude oil (MBD)
138
149
142
Natural gas liquids (MBD)
7
8
8
Natural gas (MMCFD)
478
503
484
Total Production
 
(MBOED)
224
241
230
Average Sales Prices
 
Crude oil (dollars per bbl)
$
64.94
70.71
54.21
Natural gas liquids (per bbl)
29.37
36.87
34.07
Natural gas (per mcf)
4.92
7.65
5.70
 
 
The Europe and North Africa segment consisted
 
of operations principally located in the Norwegian
 
and U.K.
sectors of the North Sea, the Norwegian Sea and
 
Libya.
 
In 2019, our Europe and North Africa operations
contributed 16 percent of our worldwide liquids production
 
and 17 percent of our natural gas production.
 
2019 vs. 2018
 
Earnings for Europe and North Africa operations
 
of $2,724 million increased $858 million
 
in 2019 compared
with 2018.
 
The increase in earnings was primarily
 
due to a $2.1 billion after-tax gain associated with
 
the
completion of the sale of two ConocoPhillips
 
U.K. subsidiaries to Chrysaor E&P Limited.
 
Earnings also
increased due to the cessation of DD&A in the second
 
quarter of 2019 for our disposed U.K. subsidiaries
 
when
these assets became held-for-sale.
 
Partly offsetting the increase in earnings were the absence
 
of a $774 million
 
 
50
after-tax gain related to the sale of a ConocoPhillips
 
subsidiary to BP, which held 16.5 percent of our 24
percent interest in the BP-operated Clair Field
 
in the U.K.; lower sales volumes primarily
 
due to the U.K.
disposition to Chrysaor completed September 30,
 
2019; and lower realized natural gas and crude
 
oil prices.
 
Average production decreased 17 MBOED in 2019, compared with 2018.
 
The decrease was mainly due to
normal field decline and a 20 MBOED disposition
 
impact from the sale of our U.K. assets to Chrysaor
completed September 30, 2019.
 
Partly offsetting these production decreases were volumes
 
from new wells
online in Norway,
 
including the Aasta Hansteen Field which
 
achieved first production in December of 2018.
 
Asset Disposition Update
On September 30, 2019, we completed the sale of
 
two ConocoPhillips U.K. subsidiaries to
 
Chrysaor E&P
Limited for proceeds of $2.2 billion after interest
 
and customary adjustments.
 
In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax
 
gain associated with this transaction.
 
Together the subsidiaries
sold indirectly held our exploration and production
 
assets in the U.K., including $1.8 billion
 
of ARO.
 
Annualized average production associated with the
 
U.K. assets sold was 50 MBOED in 2019.
 
Reserves
associated with the U.K. assets sold were 84 MMBOE
 
at the time of disposition.
 
For additional information,
see Note 5—Asset Acquisitions and Dispositions
 
in the Notes to Consolidated Financial
 
Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
51
Asia Pacific and Middle East
2019
2018
2017
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
1,929
2,070
(1,098)
Average Net Production
Crude oil (MBD)
Consolidated operations
85
89
93
Equity affiliates
13
14
14
Total crude oil
98
103
107
Natural gas liquids (MBD)
Consolidated operations
4
3
4
Equity affiliates
8
7
7
Total natural gas liquids
12
10
11
Natural gas (MMCFD)
Consolidated operations
637
626
687
Equity affiliates
1,052
1,031
1,007
Total natural gas
1,689
1,657
1,694
Total Production
 
(MBOED)
392
389
401
Average Sales Prices
 
Crude oil (dollars per bbl)
Consolidated operations
$
65.02
70.93
54.38
Equity affiliates
61.32
72.49
54.76
Total crude oil
64.52
71.14
54.43
Natural gas liquids (dollars per bbl)
Consolidated operations
37.85
47.20
41.37
Equity affiliates
36.70
45.69
38.74
Total natural gas liquids
37.10
46.13
39.75
Natural gas (dollars per mcf)
Consolidated operations
5.91
6.15
4.98
Equity affiliates
6.29
6.06
4.27
Total natural gas
6.15
6.09
4.55
 
 
The Asia Pacific and Middle East segment has
 
operations in China, Indonesia, Malaysia,
 
Australia, Timor-Leste
and Qatar.
 
During 2019,
 
Asia Pacific and Middle East contributed 13 percent
 
of our worldwide liquids
production and 60 percent of our natural gas production.
 
 
2019 vs. 2018
 
Asia Pacific and Middle East reported earnings
 
of $1,929 million in 2019, compared with
 
$2,070 million in
2018.
 
The decrease in earnings was mainly due to
 
lower realized crude oil, NGL and natural gas
 
prices;
 
lower
LNG and crude oil sales volumes; and lower equity
 
in earnings of affiliates, primarily due to a deferred
 
tax
adjustment at QG3 that resulted in a $118 million reduction to equity
 
earnings.
 
Partly offsetting this decrease in
earnings was a $164 million income tax benefit
 
related to deepwater incentive tax credits
 
from the Malaysia
Block G and a $52 million after-tax gain on disposition
 
of our interest in the Greater Sunrise Fields.
 
 
 
 
 
 
52
Average production increased 1 percent in 2019, compared with 2018.
 
The increase was primarily due to new
production from Malaysia, including first gas
 
supply from KBB to PFLNG1 in the second quarter
 
of 2019 and
first oil from Gumusut Phase 2 in the third quarter
 
of 2019;
 
and new wells online in China, including
 
Bohai
Phase 3.
 
Partly offsetting this production increase was normal
 
field decline.
 
 
Asset Dispositions Update
In the second quarter of 2019, we recognized an
 
after-tax gain of $52 million upon completion
 
of the sale of our
30 percent interest in the Greater Sunrise Fields
 
to the government of Timor-Leste for $350 million.
 
No
production or reserve impacts were associated
 
with the sale.
 
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary
 
adjustments, with an effective date of January 1, 2019.
 
In
addition, we will receive a payment of $75 million
 
upon final investment decision of the Barossa development
project.
 
These subsidiaries hold our 37.5 percent interest
 
in the Barossa Project and Caldita Field, our 56.9
percent interest in the Darwin LNG Facility
 
and Bayu-Undan Field, our 40 percent interest
 
in the Greater
Poseidon Fields, and our 50 percent interest in
 
the Athena Field.
 
This transaction is expected to be completed in
the first quarter of 2020, subject to regulatory approvals
 
and the satisfaction of other specific conditions
precedent.
 
In 2019, production associated with the
 
Australia-West assets to be sold was 48 MBOED.
 
Year
 
-end
2019 reserves associated with these assets were
 
17 MMBOE.
 
We will retain our 37.5 percent interest in the
Australia Pacific LNG project and operatorship
 
of that project’s LNG facility.
 
 
See Note 5—Asset Acquisitions and Dispositions
 
in the Notes to Consolidated Financial
 
Statements, for
additional information related to these dispositions.
 
Other International
2019
2018
2017
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
263
364
167
 
The Other International segment includes exploration
 
activities in Colombia, Chile and Argentina and
contingencies associated with prior operations.
 
2019 vs. 2018
 
Other International operations reported earnings
 
of $263 million in 2019, compared with
 
earnings of $364
million in 2018.
 
The decrease in earnings was primarily due
 
to the recognition of $417 million after-tax
 
in
other income related to a settlement agreement
 
with PDVSA in 2018, compared with $317 million
 
after-tax
associated with this settlement agreement in 2019.
 
 
In 2018 and 2019, we collected approximately
 
$0.8 billion of the $2.0 billion settlement with
 
PDVSA.
 
PDVSA has defaulted on its remaining payment obligations
 
under this agreement, we are therefore now forced
to incur additional costs as we seek to recover
 
any unpaid amounts under the agreement.
 
For additional
information, see Note 13—Contingencies and Commitments
 
in the Notes to Consolidated Financial
Statements.
 
Argentina
In January 2019,
 
we secured a 50 percent nonoperated interest
 
in the El Turbio Este Block, within the Austral
Basin in southern Argentina.
 
In 2019, we acquired and processed 3-D
 
seismic covering 500 square miles,
 
with
evaluation of the data ongoing.
 
In November 2019, we acquired interests in
 
two nonoperated blocks in the Neuquén Basin
 
targeting the Vaca
Muerta play.
 
We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest
 
in the
Aguada Federal Block.
 
In Bandurria Norte, 1 vertical and 4 horizontal
 
wells were tested and shut-in during
2019.
 
In Aguada Federal, 2 horizontal wells
 
were being tested at the end of the year.
 
 
 
 
 
 
 
 
 
 
53
Corporate and Other
Millions of Dollars
2019
2018
2017
Net Income (Loss) Attributable to ConocoPhillips
Net interest
$
(604)
(680)
(739)
Corporate general and administrative expenses
(252)
(91)
(193)
Technology
123
109
20
Other
771
(1,005)
(1,224)
$
38
(1,667)
(2,136)
 
 
2019 vs. 2018
 
Net interest consists of interest and financing expense,
 
net of interest income and capitalized interest.
 
Net
interest decreased $76 million in 2019 compared
 
with 2018,
 
primarily due to lower capitalized interest
 
on
projects; increased interest income from holding
 
higher cash balances; and lower interest on debt expense
resultant from the retirement of $4.7 billion of
 
debt in 2018; partly offset by the absence of an accrual
reduction due to a transportation cost ruling
 
by the FERC.
 
Corporate G&A expenses include compensation
 
programs and staff costs.
 
These costs increased by $161
million in 2019 compared with 2018, primarily
 
due to higher costs associated with compensation
 
and benefits,
including certain key employee compensation
 
programs and higher facility costs.
 
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 increased by $14 million in 2019 compared with
 
2018,
primarily due to higher licensing revenues.
 
 
The category “Other” includes certain foreign currency
 
transaction gains and losses, environmental costs
associated with sites no longer in operation, other
 
costs not directly associated with an operating
 
segment,
premiums incurred on the early retirement
 
of debt, unrealized holding gains or losses
 
on equity securities, and
pension settlement expense.
 
Earnings in “Other” increased by $1,776 million
 
in 2019 compared with 2018,
primarily due to an unrealized gain of $649 million
 
after-tax on our CVE common shares in
 
2019, and the
absence of a $436
 
million after-tax unrealized loss on those
 
shares in 2018.
 
Additionally, earnings increased
due to the absence of $195 million in
 
premiums on the early retirement of debt, lower pension
 
settlement
expense, and 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 19—Income Taxes, in the Notes to Consolidated
Financial Statements, for additional information
 
related to the 2017 Tax Cuts and Jobs Act.
 
 
 
 
 
 
 
 
 
54
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
2019
2018
2017
Net cash provided by operating activities
$
11,104
12,934
7,077
Cash and cash equivalents
5,088
5,915
6,325
Short-term debt
105
112
2,575
Total debt
14,895
14,968
19,703
Total equity
35,050
32,064
30,801
Percent of total debt to capital*
30
%
32
39
Percent of floating-rate debt to total debt
5
%
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 2019, the primary uses of
our available cash were $6,636 million to support
 
our ongoing capital expenditures and investments
 
program;
$3,500 million to repurchase our common stock;
 
$2,910 million net purchases of investments,
 
and $1,500
million to pay dividends on our common stock.
 
During 2019, cash and cash equivalents decreased
 
by $827
million to $5,088 million.
 
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, share repurchases,
 
dividend
payments and required debt payments.
 
Our commitment to disciplined execution of these
 
funding requirements includes cash
 
investment strategies
that position us for success in an environment
 
of short-term price volatility as well as
 
extended downturns in
commodity prices.
 
The primary objectives of these cash investment
 
strategies in priority order are to protect
principal, maintain liquidity, and provide yield and total returns.
 
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
14–Derivative and Financial Instruments.
 
 
Significant Changes in Capital
 
Operating Activities
During 2019, cash provided by operating activities
 
was $11,104 million, a 14 percent decrease from 2018.
 
The
decrease was primarily due to lower prices, lower
 
collections related to settlements reached with
 
Ecuador and
PDVSA, and a pension contribution made in conjunction
 
with the sale of two U.K. subsidiaries, partially
 
offset
by higher volumes.
 
 
While the stability of our cash flows from operating
 
activities benefits from geographic diversity, 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.
 
 
 
55
The level of absolute production volumes, as
 
well as product and location mix, impacts our cash flows.
 
Full-
year production averaged 1,348 MBOED in 2019.
 
Full-year production excluding Libya averaged
 
1,305
MBOED in 2019
 
and is expected to be 1,230 to 1,270 MBOED
 
in 2020.
 
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.
 
In 2019,
our reserve replacement, which included a net decrease
 
of 0.1 billion BOE from sales and purchases,
 
was 100
percent.
 
Increased crude oil reserves accounted for approximately
 
55 percent of the total change in reserves.
 
Our organic reserve replacement, which excludes the
 
impact of sales and purchases, was 117 percent
 
in 2019.
 
Approximately 51 percent of organic reserve additions
 
are from Lower 48, 13 percent from Alaska,
 
12 percent
from Canada, 12 percent from Europe and North
 
Africa and 12 percent from Asia Pacific and Middle
 
East.
 
 
In the five years ended December 31, 2019, our reserve
 
replacement, which included a decrease
 
of 2.0 billion
BOE from sales and purchases, was negative 34
 
percent, reflecting the impact of asset dispositions
 
and lower
prices during that period.
 
Our organic reserve replacement during the five years
 
ended December 31, 2019,
was 40
 
percent, reflecting development activities
 
as well as lower prices during that period.
 
 
Historically our reserve replacement has varied
 
considerably year to year contingent upon the timing
 
of major
projects which may have long lead times between
 
capital investment and production.
 
In the last several years,
more of our capital has been allocated to short cycle
 
time, onshore, unconventional plays.
 
Accordingly, we
believe our recent success in replacing reserves can
 
be viewed on a trailing three-year basis.
 
 
In the three years ended December 31, 2019, our reserve
 
replacement was 23 percent, reflecting the impact
 
of
asset dispositions during that period.
 
Our organic reserve replacement during the three years
 
ended December
31, 2019, which excludes a decrease of 1.8 billion
 
BOE related to sales and purchases, was 143 percent,
reflecting reserve additions from development activities.
 
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. For additional information about
 
our
2020 capital budget, see the “2020 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.
 
We have reported revisions as
increases to reserves in the current period, however
 
in prior periods,
 
reported revisions as decreases to
reserves. It is not possible to reliably predict
 
how revisions will impact reserve quantities
 
in the future.
 
Investing Activities
Proceeds from asset sales in 2019 were $3.0 billion.
 
We
 
completed the sale of two ConocoPhillips U.K.
subsidiaries to Chrysaor E&P Limited for $2.2
 
billion.
 
We also completed the sale of several assets including
our 30 percent interest in the Greater Sunrise Fields
 
for $350 million and received $106 million
 
of contingent
payments from Cenovus Energy.
 
 
In the fourth quarter of 2019, we entered into an
 
agreement to sell the subsidiaries that hold
 
our Australia-West
assets and operations to Santos for $1.39 billion,
 
plus customary adjustments.
 
In addition, we will receive a
payment of $75 million upon final investment
 
decision of the Barossa development project.
 
Also in the fourth
 
 
56
quarter of 2019, we signed an agreement to sell
 
our interests in the Niobrara shale play
 
for $380 million, plus
customary adjustments,
 
and overriding royalty interests in certain
 
future wells.
 
Both transactions are subject to
regulatory approval and other conditions precedent
 
and expected to close in the first quarter of 2020.
 
 
Investing activities in 2019 also included net purchases
 
of $2.9 billion of investments in short-term
 
and long-
term financial instruments. These investments include
 
time deposits, commercial paper as well as debt
securities classified as available for sale.
 
The investment in short-term instruments
 
was $2.8 billion, the
remaining $0.1 billion was invested in long-term
 
debt securities.
 
For additional information, see Note 14–
Derivative and Financial Instruments.
 
Proceeds from asset sales in 2018 were $1.1 billion.
 
We completed several undeveloped acreage transactions
in our Lower 48 segment for a total of $267 million
 
after customary adjustments and another transaction
 
in our
Lower 48 segment for $112 million after customary adjustments.
 
We completed the sale of our interests in the
Barnett to Lime Rock Resources for $196 million
 
after customary adjustments.
 
We also completed the sale of
a ConocoPhillips subsidiary to BP and received
 
$253 million net proceeds.
 
The subsidiary held 16.5 percent
of our 24 percent interest in the BP-operated
 
Clair Field in the U.K.
 
During 2018, we received $95 million of
contingent payments from Cenovus Energy.
 
For additional information on our dispositions,
 
see Note 5—Asset Acquisitions and Dispositions
 
in the Notes
to Consolidated Financial Statements.
 
Commercial Paper and Credit Facilities
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.
 
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 $6.0 billion commercial paper program,
which is primarily a funding source for short-term
 
working capital needs.
 
Commercial paper maturities are
generally limited to 90 days.
 
We had no commercial paper outstanding in programs in place at December 31,
2019 or December 31, 2018.
 
We had no direct outstanding borrowings or letters of credit under the revolving
credit facility at December 31, 2019 and December
 
31, 2018.
 
Since we had no commercial paper outstanding
and had issued no letters of credit, we had access to
 
$6.0 billion in borrowing capacity under our revolving
credit facility at December 31, 2019.
 
Our current long-term debt ratings remained
 
unchanged in 2019 and are as follows:
 
Fitch - “A” with a “stable”
outlook; Moody’s Investors Services - “A3” with a “stable” outlook; and
 
Standard & Poor’s - “A” with a
stable outlook.
 
We do not have any ratings triggers on any of our corporate debt that would
 
cause an
automatic default, and thereby impact our access
 
to liquidity, in the event of a downgrade of our credit rating.
 
If our credit rating were downgraded, 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
 
 
57
of credit as collateral.
 
At December 31, 2019 and 2018, we had direct
 
bank letters of credit of $277 million
and $323 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.
 
 
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which
 
we, as a well-known
seasoned issuer, have the ability to issue and sell an indeterminate
 
amount of various types of debt and equity
securities.
 
 
 
Off-Balance Sheet Arrangements
 
As part of our normal ongoing business operations
 
and consistent with normal industry practice,
 
we enter into
numerous agreements with other parties to pursue
 
business opportunities, which share costs
 
and apportion
risks among the parties as governed by the agreements.
 
For information about guarantees, see Note 12—Guarantees,
 
in the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
 
 
Capital Requirements
 
For information about our capital expenditures
 
and investments, see the “Capital Expenditures”
 
section.
 
Our debt balance at December 31, 2019, was $14,895
 
million, a decrease of $73 million from the balance
 
at
December 31, 2018.
 
For more information on Debt, see Note 11—Debt, in the Notes
 
to Consolidated
Financial Statements.
 
On January 30, 2019, we announced a quarterly
 
dividend of $0.305 per share.
 
The dividend was paid on
March 1, 2019, to stockholders of record at the close
 
of business on February 11, 2019.
 
On May 1, 2019, we
announced a quarterly dividend of $0.305 per share.
 
The dividend was paid on June 3, 2019, to stockholders
of record at the close of business on May 13,
 
2019.
 
On July 11, 2019, we announced a quarterly dividend of
$0.305 per share.
 
The dividend was paid on September 3, 2019, to
 
stockholders of record at the close of
business on July 22, 2019.
 
On October 7, 2019, we announced a 38 percent increase
 
in the quarterly dividend
to $0.42 per share.
 
The dividend was paid on December 2, 2019, to
 
stockholders of record at the close of
business on October 17, 2019.
 
In February 2020, we announced a quarterly dividend
 
of $0.42 per share,
payable March 2, 2020, to stockholders of record
 
at the close of business on February 14, 2020.
 
 
In late 2016, we initiated our current share repurchase
 
program.
 
As of December 31, 2019, we had announced
a total authorization to repurchase $15 billion
 
of our common stock.
 
We repurchased $3 billion in 2017, $3
billion in 2018 and $3.5 billion in 2019.
 
Of the remaining authorization, we expect to
 
repurchase $3 billion in
2020.
 
In February 2020, we announced that the
 
Board of Directors approved an increase to
 
our authorization
from $15 billion to $25 billion, to support our
 
plan for future share repurchases.
 
Whether we undertake these
additional repurchases is ultimately subject to numerous
 
considerations, market conditions and other factors.
 
See Risk Factors -“Our ability to declare and pay
 
dividends and repurchase shares is subject to certain
considerations.”
 
Since our share repurchase program began
 
in November 2016, we have repurchased 169
million shares at a cost of $9.6 billion through
 
December 31, 2019.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
58
Contractual Obligations
The table below summarizes our aggregate contractual
 
fixed and variable obligations as of December
 
31, 2019:
Millions of Dollars
Payments Due by Period
 
Up to 1
Years
Years
After
Total
 
Year
2–3
4–5
5 Years
Debt obligations (a)
$
14,175
18
1,018
605
12,534
Finance lease obligations (b)
720
87
157
141
335
Total debt
14,895
105
1,175
746
12,869
Interest on debt
11,339
856
1,671
1,603
7,209
Operating lease obligations (c)
1,050
379
377
145
149
Purchase obligations (d)
8,671
3,237
1,745
1,327
2,362
Other long-term liabilities
Pension and postretirement benefit
contributions (e)
1,375
440
540
395
-
Asset retirement obligations (f)
6,206
997
282
309
4,618
Accrued environmental costs (g)
171
28
33
21
89
Unrecognized tax benefits (h)
82
82
(h)
(h)
(h)
Total
$
43,789
6,124
5,823
4,546
27,296
 
 
(a)
 
Includes $204 million of net unamortized premiums,
 
discounts and debt issuance costs.
 
See Note 11—
Debt, in the Notes to Consolidated Financial Statements,
 
for additional information.
 
(b)
 
See Note 17—Non-Mineral Leases, in the Notes to
 
Consolidated Financial Statements, for
 
additional
information.
 
 
(c)
 
Includes $31 million of short-term leases that
 
are not recorded on our consolidated balance
 
sheet.
 
See
Note 17—Non-Mineral Leases, in the Notes to
 
Consolidated Financial Statements, for
 
additional
information.
 
 
(d)
 
Represents any agreement to purchase goods
 
or services that is enforceable and legally binding
 
and that
specifies all significant terms, presented on an undiscounted
 
basis.
 
Does not include purchase
commitments for jointly owned fields and facilities
 
where we are not the operator.
 
 
The majority of the purchase obligations are market-based
 
contracts related to our commodity business.
 
Product purchase commitments with third parties
 
totaled $2,426 million.
 
 
Purchase obligations of $5,111 million are related to agreements to access and
 
utilize the capacity of
third-party equipment and facilities, including
 
pipelines and LNG and product terminals, to
 
transport,
process, treat and store commodities.
 
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.
 
 
(e)
 
Represents contributions to qualified and nonqualified
 
pension and postretirement benefit plans
 
for the
years 2020 through 2024.
 
For additional information related to expected
 
benefit payments subsequent to
2024, see Note 18—Employee Benefit Plans,
 
in the Notes to Consolidated Financial
 
Statements.
 
(f)
 
Represents estimated discounted costs to retire
 
and remove long-lived assets at the end of their
operations.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
59
(g)
 
Represents estimated costs for accrued environmental
 
expenditures presented on a discounted basis
 
for
costs acquired in various business combinations
 
and an undiscounted basis for all other accrued
environmental costs.
 
(h)
 
Excludes unrecognized tax benefits of $1,095
 
million because the ultimate disposition and timing
 
of any
payments to be made with regard to such amounts
 
are not reasonably estimable.
 
Although unrecognized
tax benefits are not a contractual obligation,
 
they are presented in this table because they
 
represent
potential demands on our liquidity.
 
Capital Expenditures and Investments
Millions of Dollars
2019
2018
2017
Alaska
$
1,513
1,298
815
Lower 48
3,394
3,184
2,136
Canada
368
477
202
Europe and North Africa
708
877
872
Asia Pacific and Middle East
584
718
482
Other International
8
6
21
Corporate and Other
61
190
63
Capital Program
$
6,636
6,750
4,591
 
 
Our capital expenditures and investments
 
for the three-year period ended December 31,
 
2019, totaled $18.0
billion.
 
The 2019 expenditures supported key exploration
 
and developments, primarily:
 
 
 
Development, appraisal and exploration activities
 
in the Lower 48, including Eagle Ford, Permian
Unconventional, 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; leasehold acquisition
 
in the
Greater Kuparuk Area.
 
 
Development activities across assets in Norway, as well as for assets in the U.K. that
 
recently have
been sold.
 
 
Optimization of oil sands development and appraisal
 
activities in liquids-rich plays in Canada.
 
 
Signature bonus for Indonesia Corridor Block
 
production sharing contract, as well as continued
development in China, Malaysia, Australia, and
 
Indonesia.
 
 
 
2020 CAPITAL BUDGET
 
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
The plan includes
funding for ongoing development drilling
 
programs, major projects, exploration and appraisal
 
activities, as
well as base maintenance.
 
Capital spend is expected to be higher in the first
 
quarter largely from winter
construction and exploration and appraisal drilling
 
in Alaska.
 
This guidance does not include capital for
acquisitions.
 
 
For information on PUDs and the associated costs
 
to develop these reserves, see the “Oil and
 
Gas Operations”
section in this report.
 
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
 
 
 
60
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
minimum of the range is accrued.
 
We do not reduce these liabilities for potential insurance or third-party
recoveries.
 
If applicable, we accrue receivables for probable
 
insurance or other third-party recoveries.
 
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 13—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 19—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.
 
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.
 
61
 
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, 2019, there were 15 sites around
 
the U.S. in which we were identified as a potentially
responsible party under CERCLA and comparable
 
state laws.
 
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
 
62
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 $511 million in 2019 and are expected
 
to be about $545 million per year
in 2020 and 2021.
 
Capitalized environmental costs were $194 million
 
in 2019 and are expected to be about
$225 million per year in 2020 and 2021.
 
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, 2019, our balance sheet included
 
total accrued environmental costs of
 
$171 million,
compared with $178 million at December 31,
 
2018, 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.
 
 
 
63
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 or 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 2019
 
was
approximately $8 million before-tax.
 
The Alberta Carbon Competitiveness Incentive
 
Regulation (CCIR) requires any existing facility
 
with
emissions equal to or greater than 100,000 metric
 
tonnes of carbon dioxide, or equivalent,
 
per year to
meet an industry benchmark intensity.
 
The total cost of these regulations in 2019
 
was approximately
$4 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 former U.S. administration 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 2019 was approximately $30 million (net
 
share before-tax).
 
We also incur a carbon tax for
emissions from fossil fuel combustion in our
 
British Columbia and Alberta Operations
 
totaling just
over $0.8 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 on Climate Change, setting
 
out a new process for achieving global
 
emission
reductions.
 
While the U.S. announced its intention
 
to withdraw from the Paris Agreement, there
 
is no
guarantee that the commitments made by the
 
U.S. will not be implemented, in whole or
 
in part, by
U.S. state and local governments or by major corporations
 
headquartered in the U.S.
 
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.
 
 
64
 
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.
 
 
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 different scopes.
 
Scope 1 and Scope 2 GHG emissions
 
help us understand
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.
 
Our corporate authorization process requires all
 
qualifying projects to run a GHG pricing
 
sensitivity using a
corporate price of $40 per tonne of carbon
 
dioxide equivalent, plus annual inflation, for
 
all Scope 1 and Scope
2 GHG emissions produced in 2024 and later.
 
Projects in jurisdictions with existing GHG pricing
 
regimes
must incorporate that existing GHG price and its
 
forecast into their base case economics.
 
Where the existing
GHG price is below the corporate price, the
 
$40 per tonne of carbon dioxide equivalent
 
sensitivity must also be
run from 2024 onward.
 
Thus, 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.
 
In December 2018, we became a founding member
 
of the 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.
 
 
In 2017 and 2018, cities, counties, and a state
 
government in California, New York, Washington, Rhode Island
and Maryland, as well as the Pacific Coast Federation
 
of Fishermen’s Association, Inc., have filed lawsuits
against oil and gas companies, including ConocoPhillips,
 
seeking compensatory damages and equitable
 
relief
to abate alleged climate change impacts.
 
ConocoPhillips is vigorously defending against
 
these lawsuits.
 
The
lawsuits brought by the Cities of San Francisco,
 
Oakland and New York have been dismissed by the district
courts and appeals are pending.
 
Lawsuits filed by other cities and counties
 
in California and Washington are
currently stayed pending resolution of the appeals
 
brought by the Cities of San Francisco and
 
Oakland to the
U.S. Court of Appeals for the Ninth Circuit.
 
Lawsuits filed in Maryland and Rhode Island
 
are proceeding in
state court while rulings in those matters, on the
 
issue of whether the matters should proceed
 
in state or federal
court, are on appeal to the U.S. Court of Appeals
 
for the Fourth Circuit and First Circuit,
 
respectively.
 
 
 
65
Several Louisiana parishes and individual landowners
 
have filed lawsuits against oil and gas companies,
including ConocoPhillips, seeking compensatory
 
damages in connection with historical oil
 
and gas operations
in Louisiana.
 
All parish lawsuits are stayed pending an appeal
 
to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or
 
state court.
 
ConocoPhillips will vigorously defend against
these lawsuits.
 
 
 
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards
 
and credit carryforwards.
 
Valuation
 
allowances have been established to reduce
 
these deferred tax assets to an amount that
 
will, more
likely than not, be realized.
 
Based on our historical taxable income, our expectations
 
for the future, and
available tax-planning strategies, management
 
expects the net deferred tax assets will be realized
 
as offsets to
reversing deferred tax liabilities.
 
 
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 geological and geophysical
 
seismic information, prior to the discovery
 
of proved
reserves, is expensed as incurred, similar to
 
accounting for research and development
 
costs.
 
However,
leasehold acquisition costs and exploratory well
 
costs are capitalized on the balance sheet
 
pending
determination of whether proved oil and gas reserves
 
have been recognized.
 
Property Acquisition
 
Costs
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 2019, the remaining $3.5 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
$2.1 billion is concentrated in 10 major development
 
areas, the majority of which are not expected to
 
move to
proved properties in 2020,
 
and $0.6 billion is held for sale.
 
Management periodically assesses individually
 
 
 
66
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 2019,
 
total suspended well costs were $1,020 million,
 
compared with $856 million at year-end
2018.
 
For additional information on suspended wells,
 
including an aging analysis, see Note 8—Suspended
Wells and Other Exploration Expenses, in the Notes to Consolidated Financial
 
Statements.
 
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 be permanently
 
shut down for
economic reasons is based on 12-month average
 
prices and current costs.
 
This estimated date when production
 
67
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, 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 2019, the net book value of productive PP&E
subject to a unit-of-production calculation was
 
approximately $35 billion and the DD&A recorded
 
on these
assets in 2019 was approximately $5.8 billion.
 
The estimated proved developed reserves for
 
our consolidated
operations were 3.3 billion BOE at the end
 
of 2018 and 3.2
 
billion BOE at the end of 2019.
 
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 2019
 
would have increased by an estimated $642
 
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 and
annually in the fourth quarter following updates
 
to corporate planning assumptions.
 
If there is an indication
the carrying amount of an asset may not be recovered,
 
the asset is monitored by management through
 
an
established process where changes to significant
 
assumptions such as prices, volumes and future
 
development
plans are reviewed.
 
If, upon review, the sum of the undiscounted before-tax cash flows is
 
less than the
carrying value of the asset group, the carrying
 
value is written down to estimated fair
 
value.
 
Individual assets
are grouped for impairment purposes based on a
 
judgmental assessment of 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 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 judgmental assessments of future production
 
volumes, commodity prices, operating
 
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 9—Impairments, in the Notes to
Consolidated Financial Statements, for additional
 
information.
 
Investments in nonconsolidated entities
 
accounted for under the equity method are reviewed
 
for impairment
when there is evidence of a loss in value and annually
 
following updates to corporate planning assumptions.
 
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 it is determined such a loss in value
 
is 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 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 6—Investments,
Loans and Long-Term Receivables,
 
in the Notes to Consolidated Financial Statements,
 
for additional
 
68
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.
 
Estimating future asset removal
costs is difficult.
 
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.
 
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, are also subject to change.
 
 
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
10—Asset Retirement Obligations and Accrued
 
Environmental Costs, in the Notes to Consolidated
 
Financial
Statements, for additional information.
 
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
$1,000 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
$100 million, while a 100 basis-point decrease
 
in the return on plan assets assumption
 
would increase annual
benefit expense by $60 million.
 
In determining the discount rate, we use yields
 
on high-quality fixed income
investments matched to the estimated benefit
 
cash flows of our plans.
 
We are also exposed to the possibility
 
69
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 18—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 13—Contingencies
 
and Commitments.
 
70
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, and objectives of management for future operations,
 
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,”
“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.
 
 
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,
 
including, but not limited to, the
following:
 
 
 
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 costs
 
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,
announced and future exploration and production
 
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, global health epidemics, terrorism,
 
cyber attacks, and information
technology failures, constraints or disruptions.
 
Changes in international monetary conditions and
 
foreign currency exchange rate fluctuations.
 
71
 
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
 
or 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 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;
 
the impact of and uncertainty surrounding the
 
U.K.’s
decision to withdraw from the EU; 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, including changes
 
resulting from the implementation and interpretation
 
of
the Tax Cuts and Jobs Act.
 
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.
 
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
 
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 asset dispositions or acquisitions, including
 
the
diversion
 
of management time and attention.
 
Our inability to deploy the net proceeds from any
 
asset dispositions we undertake 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 expenditure reductions.
 
The factors generally described in Item 1A—Risk
 
Factors in this 2019 Annual Report on Form 10-K
and any additional risks described in our other filings
 
with the SEC.
 
 
 
72
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, 2019,
 
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, 2019 and 2018,
 
was immaterial to our
consolidated cash flows and net income attributable
 
to ConocoPhillips.
 
 
Interest Rate Risk
The following table provides information
 
about our debt instruments that are sensitive to
 
changes in U.S.
interest rates.
 
The table presents
 
principal cash flows and related weighted-average
 
interest rates by expected
maturity dates.
 
Weighted-average variable rates are based on effective rates at the reporting date.
 
The
carrying amount of our floating-rate debt approximates
 
its fair value.
 
The fair value of the fixed-rate debt is
measured using prices available from a pricing
 
service that is corroborated by market
 
data.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
73
Millions of Dollars Except as Indicated
Debt
Fixed
Average
Floating
Average
Rate
Interest
Rate
Interest
Expected Maturity Date
Maturity
Rate
Maturity
 
Rate
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
Year
 
-End 2018
2019
$
17
-
%
$
-
-
%
2020
-
-
-
-
2021
123
9.13
-
-
2022
343
2.54
500
3.52
2023
106
7.20
-
-
Remaining years
12,599
6.16
283
1.78
Total
$
13,188
$
783
Fair value
$
15,364
$
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, 2019 and 2018, we held foreign
 
currency exchange forwards hedging cross-border
commercial activity and foreign currency exchange
 
swaps and options for purposes of mitigating
 
our cash-
related exposures.
 
Although these forwards, swaps and options
 
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, 2019,
 
we had outstanding foreign currency exchange
 
forward contracts to sell $1.35 billion
CAD at $0.748 CAD against the U.S. dollar.
 
At December 31, 2018, we had outstanding foreign
 
currency
zero-cost collars buying the right to sell $1.25 billion
 
CAD at $0.707
 
CAD and selling the right to buy $1.25
billion CAD at $0.842 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, 2019 and
 
December 31,
2018, was a before-tax loss of $28 million and a before-tax
 
gain of $6
 
million, respectively.
 
Based on an
adverse hypothetical 10 percent change in the
 
December 2019 and December 2018 exchange rate, this
 
would
result in an additional before-tax loss of $115 million and $17 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
74
The gross notional and fair value of these positions
 
at December 31, 2019 and 2018, were as follows:
 
In Millions
Foreign Currency Exchange Derivatives
Notional*
Fair Value**
2019
2018
2019
2018
Sell U.S. dollar, buy British pound
USD
-
805
-
(5)
Sell Canadian dollar, buy U.S. dollar
CAD
1,350
1,250
(28)
6
Buy Canadian dollar, sell U.S. dollar
CAD
13
8
-
-
Sell British pound, buy Norwegian krone
GBP
-
9
-
-
Sell British pound, buy euro
GBP
-
12
-
-
Buy British pound, sell euro
GBP
4
-
-
-
 
*Denominated in USD, CAD and GBP.
**Denominated in USD.
For additional information about our use of derivative
 
instruments, see Note 14—Derivative and Financial
Instruments, in the Notes to Consolidated Financial
 
Statements.
 
 
75
Item 8.
 
FINANCIAL STATEMENTS AND SUPPLEMENTARY
 
DATA
 
 
 
 
CONOCOPHILLIPS
 
 
 
INDEX TO FINANCIAL STATEMENTS
Page
Report of Management ............................................................................................................................
 
76
Reports of Independent Registered Public Accounting
 
Firm .................................................................
 
77
Consolidated Income Statement for the years ended
 
December 31, 2019,
 
2018 and 2017
 
....................
 
81
Consolidated Statement of Comprehensive Income
 
for the years ended
 
December 31, 2019, 2018 and 2017
 
..................................................................................................
 
82
Consolidated Balance Sheet at December 31, 2019
 
and 2018
 
................................................................
 
83
Consolidated Statement of Cash Flows for the years
 
ended December 31, 2019,
 
2018 and 2017
 
.........
 
84
Consolidated Statement of Changes in Equity for
 
the years ended
December 31, 2019, 2018 and 2017
 
..................................................................................................
 
85
Notes to Consolidated Financial Statements
 
............................................................................................
 
86
Supplementary Information
Oil and Gas Operations
 
..............................................................................................................
 
150
Selected Quarterly Financial Data
 
..............................................................................................
 
178
Condensed Consolidating Financial Information
 
.......................................................................
 
179
 
 
 
76
Report 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, 2019.
 
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, 2019.
 
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2019, and their report is included
 
herein.
 
 
/s/ Ryan M. Lance
/s/ Don E. Wallette, Jr.
Ryan M. Lance
 
Don E. Wallette, Jr.
Chairman and
Chief Executive Officer
 
Executive Vice President and
 
Chief Financial Officer
 
 
 
February 18, 2020
 
 
77
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, 2019 and 2018, 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, 2019, and the related notes, condensed
 
consolidating financial information listed in
 
the Index at
Item 8, and financial statement schedule listed
 
in Item 15(a) (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, 2019 and 2018, and the
 
results of its
operations and its cash flows for each of the three
 
years in the period ended December 31, 2019,
 
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, 2019,
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 18, 2020,
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.
 
 
78
Accounting for asset retirement obligations
 
for certain offshore properties
Description of
the Matter
At December 31, 2019, the asset retirement
 
obligation (“ARO”) balance totaled $6.2
billion. As further described in Note 10, the Company
 
records AROs in the period in
which they are incurred, typically when the asset
 
is installed at the production location.
The estimation of obligations related to certain
 
offshore assets requires significant
judgment given the magnitude 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 underlying removal cost
estimates.
Depreciation, depletion and amortization of
 
proved oil and gas properties
Description of
the Matter
At December 31, 2019, the net book value of
 
the Company’s properties, plants and
equipment was $42.3 billion, and depreciation,
 
depletion and amortization (DD&A)
expense was $6.1 billion for the year then ended.
 
As described in Note 1, DD&A of
properties, plants and equipment on producing
 
hydrocarbon properties and certain
pipeline and LNG assets (those which are expected
 
to have a declining utilization
pattern) are determined by the unit-of-production method
 
based on proved oil and gas
reserves, as estimated by the Company’s internal reservoir engineers. Proved
 
oil and gas
reserve estimates are based on geological and engineering
 
assessments of in-place
hydrocarbon volumes, the production plan, historical
 
extraction recovery and processing
yield factors, installed plant operating capacity
 
and approved operating limits. Significant
judgment is required by the Company’s internal reservoir engineers
 
in evaluating
geological and engineering data when estimating
 
proved oil and gas reserves. Estimating
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 a third-party petroleum
 
engineering 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.
 
79
Auditing the Company’s DD&A calculation is complex because of the
 
use of the work of
the internal reservoir engineers and third-party petroleum
 
engineering firm and the
evaluation of management’s determination of the inputs described above
 
used by the
internal reservoir engineers in estimating
 
proved oil and gas reserves.
 
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design and tested the operating
effectiveness of the Company’s internal controls over its process to calculate DD&A,
including management’s controls over the completeness and accuracy of the
 
financial
data provided to the internal reservoir engineers
 
for use in estimating proved oil and gas
reserves.
Our audit procedures included, among others,
 
evaluating the professional qualifications
and objectivity of the Company’s internal reservoir engineers primarily
 
responsible for
overseeing the preparation of the reserve estimates
 
and the third-party petroleum
engineering firm used to review the Company’s processes and controls.
 
In addition, in
assessing whether we can use the work of the internal
 
reservoir engineers, we evaluated
the completeness and accuracy of the financial data
 
and inputs described above used by
the internal reservoir engineers in estimating
 
proved oil and gas reserves by agreeing
them to source documentation and we identified
 
and evaluated corroborative and
contrary evidence. For proved undeveloped reserves,
 
we evaluated management’s
development plan for compliance with the SEC
 
rule that undrilled locations are
scheduled to be drilled within five years, unless
 
specific circumstances justify a longer
time, by assessing consistency of the development
 
projections with the Company’s drill
plan. We also tested the accuracy of the DD&A calculations, including comparing the
proved oil and gas reserve amounts used in the
 
calculation to the Company’s reserve
report.
 
 
/s/ Ernst & Young LLP
 
We have served as ConocoPhillips’ auditor since 1949.
 
Houston, Texas
February 18, 2020
 
 
 
80
Report of Independent Registered Public Accounting Firm
 
 
To the Stockholders
 
and the Board of Directors of ConocoPhillips
 
Opinion on Internal Control over Financial Reporting
We have audited
 
ConocoPhillips’ internal control over financial reporting as of December 31,
 
2019, 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, 2019,
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, 2019 and 2018, 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, 2019, and the related notes,
 
condensed consolidating
financial information listed in the Index at Item 8, and financial statement schedule
 
listed in Item 15(a) and our
report dated February 18, 2020, 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
 
“Report 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 18, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
81
Consolidated Income Statement
ConocoPhillips
Years
 
Ended December 31
Millions of Dollars
2019
2018
2017
Revenues and Other Income
Sales and other operating revenues
$
32,567
36,417
29,106
Equity in earnings of affiliates
779
1,074
772
Gain on dispositions
1,966
1,063
2,177
Other income
 
1,358
173
529
Total Revenues and
 
Other Income
36,670
38,727
32,584
Costs and Expenses
Purchased commodities
11,842
14,294
12,475
Production and operating expenses
5,322
5,213
5,162
Selling, general and administrative expenses
556
401
427
Exploration expenses
743
369
934
Depreciation, depletion and amortization
6,090
5,956
6,845
Impairments
405
27
6,601
Taxes other than income
 
taxes
953
1,048
809
Accretion on discounted liabilities
326
353
362
Interest and debt expense
778
735
1,098
Foreign currency transaction (gains) losses
66
(17)
35
Other expenses
65
375
451
Total Costs and Expenses
27,146
28,754
35,199
Income (loss) before income taxes
9,524
9,973
(2,615)
Income tax provision (benefit)
2,267
3,668
(1,822)
Net income (loss)
7,257
6,305
(793)
Less: net income attributable to noncontrolling interests
(68)
(48)
(62)
Net Income (Loss) Attributable to ConocoPhillips
$
7,189
6,257
(855)
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
6.43
5.36
(0.70)
Diluted
6.40
5.32
(0.70)
Average Common
 
Shares Outstanding
(in thousands)
Basic
1,117,260
1,166,499
1,221,038
Diluted
1,123,536
1,175,538
1,221,038
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
82
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years
 
Ended December 31
Millions of Dollars
2019
2018
2017
Net Income (Loss)
$
7,257
6,305
(793)
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period
-
(7)
2
Reclassification adjustment for amortization of prior
service credit included in net income (loss)
(35)
(40)
(38)
Net change
(35)
(47)
(36)
Net actuarial gain (loss) arising during the period
(55)
(150)
19
Reclassification adjustment for amortization of net
actuarial losses included in net income (loss)
146
279
247
Net change
91
129
266
Nonsponsored plans*
(3)
(1)
(2)
Income taxes on defined benefit plans
(2)
(42)
(81)
Defined benefit plans, net of tax
51
39
147
Unrealized holding loss on securities
-
-
(58)
Unrealized loss on securities, net of tax
-
-
(58)
Foreign currency translation adjustments
699
(645)
586
Income taxes on foreign currency translation adjustments
(4)
3
-
Foreign currency translation adjustments, net of tax
695
(642)
586
Other Comprehensive Income (Loss), Net of
 
Tax
746
(603)
675
Comprehensive Income (Loss)
8,003
5,702
(118)
Less: comprehensive income attributable to noncontrolling interests
(68)
(48)
(62)
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
7,935
5,654
(180)
*Plans for which ConocoPhillips is not the primary obligor
primarily those administered by equity affiliates.
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
83
Consolidated Balance Sheet
 
ConocoPhillips
At December 31
Millions of Dollars
2019
2018
Assets
Cash and cash equivalents
$
5,088
5,915
Short-term investments
3,028
248
Accounts and notes receivable (net of allowance of $
13
 
million in 2019
and $
25
 
million in 2018)
3,267
3,920
Accounts and notes receivable—related parties
134
147
Investment in Cenovus Energy
2,111
1,462
Inventories
1,026
1,007
Prepaid expenses and other current assets
2,259
575
Total Current Assets
16,913
13,274
Investments and long-term receivables
8,687
9,329
Loans and advances—related parties
219
335
Net properties, plants and equipment (net of accumulated depreciation,
 
depletion
and amortization of $
55,477
 
million in 2019 and $
64,899
 
million in 2018)
42,269
45,698
Other assets
2,426
1,344
Total Assets
$
70,514
69,980
Liabilities
Accounts payable
$
3,176
3,863
Accounts payable—related parties
24
32
Short-term debt
105
112
Accrued income and other taxes
1,030
1,320
Employee benefit obligations
663
809
Other accruals
2,045
1,259
Total Current Liabilities
7,043
7,395
Long-term debt
14,790
14,856
Asset retirement obligations and accrued environmental costs
5,352
7,688
Deferred income taxes
4,634
5,021
Employee benefit obligations
1,781
1,764
Other liabilities and deferred credits
1,864
1,192
Total Liabilities
35,464
37,916
Equity
Common stock (
2,500,000,000
 
shares authorized at $
0.01
 
par value)
Issued (2019—
1,795,652,203
 
shares; 2018—
1,791,637,434
 
shares)
Par value
18
18
Capital in excess of par
46,983
46,879
Treasury stock (at cost: 2019—
710,783,814
 
shares; 2018—
653,288,213
 
shares)
(46,405)
(42,905)
Accumulated other comprehensive loss
(5,357)
(6,063)
Retained earnings
39,742
34,010
Total Common
 
Stockholders’ Equity
34,981
31,939
Noncontrolling interests
69
125
Total Equity
35,050
32,064
Total Liabilities and Equity
$
70,514
69,980
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
84
Consolidated Statement of Cash Flows
ConocoPhillips
Years
 
Ended December 31
Millions of Dollars
2019
2018
2017
Cash Flows From Operating Activities
Net income (loss)
$
7,257
6,305
(793)
Adjustments to reconcile net income (loss) to net cash provided by
 
operating activities
Depreciation, depletion and amortization
6,090
5,956
6,845
Impairments
405
27
6,601
Dry hole costs and leasehold impairments
421
95
566
Accretion on discounted liabilities
326
353
362
Deferred taxes
(444)
283
(3,681)
Undistributed equity earnings
594
152
(232)
Gain on dispositions
(1,966)
(1,063)
(2,177)
Other
(1,000)
191
(429)
Working
 
capital adjustments
Decrease (increase) in accounts and notes receivable
505
235
(886)
Decrease (increase) in inventories
(67)
86
(55)
Decrease (increase) in prepaid expenses and other current assets
37
(55)
69
Increase (decrease) in accounts payable
(378)
(52)
265
Increase (decrease) in taxes and other accruals
(676)
421
622
Net Cash Provided by Operating Activities
11,104
12,934
7,077
Cash Flows From Investing Activities
Capital expenditures and investments
(6,636)
(6,750)
(4,591)
Working
 
capital changes associated with investing activities
(103)
(68)
132
Proceeds from asset dispositions
3,012
1,082
13,860
Net sales (purchases) of investments
(2,910)
1,620
(1,790)
Collection of advances/loans—related parties
127
119
115
Other
(108)
154
36
Net Cash Provided by (Used in) Investing Activities
(6,618)
(3,843)
7,762
Cash Flows From Financing Activities
Repayment of debt
(80)
(4,995)
(7,876)
Issuance of company common stock
(30)
121
(63)
Repurchase of company common stock
(3,500)
(2,999)
(3,000)
Dividends paid
(1,500)
(1,363)
(1,305)
Other
(119)
(123)
(112)
Net Cash Used in Financing Activities
(5,229)
(9,359)
(12,356)
Effect of Exchange Rate Changes on Cash, Cash Equivalents
 
and Restricted Cash
(46)
(117)
232
Net Change in Cash, Cash Equivalents and Restricted Cash
(789)
(385)
2,715
Cash, cash equivalents and restricted cash at beginning of period
6,151
6,536
3,610
Cash, Cash Equivalents and Restricted Cash at End of Period
$
5,362
6,151
6,325
Restricted cash of $
90
 
million and $
184
 
million are included in the “Prepaid expenses and other current assets” and “Other assets” lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2019.
Restricted cash totaling $
236
 
million is included in the “Other assets” line of our Consolidated
 
Balance Sheet as of December 31, 2018.
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
85
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
December 31, 2016
$
18
46,507
(36,906)
(6,193)
31,548
252
35,226
Net income (loss)
(855)
62
(793)
Other comprehensive income
675
675
Dividends paid ($
1.06
 
per share of common stock)
(1,305)
(1,305)
Repurchase of company common stock
(3,000)
(3,000)
Distributions to noncontrolling interests and other
(120)
(120)
Distributed under benefit plans
115
115
Other
3
3
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
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
December 31, 2019
$
18
46,983
(46,405)
(5,357)
39,742
69
35,050
 
*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.
**See Note 2—Changes in Accounting Principles for additional
 
information.
 
See Notes to Consolidated Financial Statements.
 
 
86
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 and North Africa, Asia Pacific
 
and Middle East, and Other International.
 
For
additional information, see Note 25—Segment
 
Disclosures and Related Information.
 
 
 
 
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.
 
 
 
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.
 
 
87
 
 
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.
 
 
 
Oil and Gas Exploration and Development
—Oil and gas exploration and development
 
costs are
accounted for using the successful efforts method of
 
accounting.
Property Acquisition Costs
—Oil and gas leasehold acquisition costs are
 
capitalized and included in
the balance sheet caption PP&E.
 
Leasehold impairment is recognized based
 
on exploratory
experience and management’s judgment.
 
Upon achievement of all conditions necessary for
 
reserves
to be classified as proved, the associated leasehold
 
costs are reclassified to proved properties.
Exploratory Costs
—Geological and geophysical costs and the
 
costs of carrying and retaining
undeveloped properties are expensed as incurred.
 
Exploratory well costs are capitalized, or
“suspended,” on the balance sheet pending further
 
evaluation of whether economically recoverable
reserves have been found.
 
If economically recoverable reserves are not found,
 
exploratory well costs
are expensed as dry holes.
 
If exploratory wells encounter potentially
 
economic quantities of oil and
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
 
88
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 8—
Suspended Wells and Other 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 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 and annually in the fourth
 
quarter
following updates to corporate planning assumptions.
 
If there is an indication the carrying amount of
 
an
asset may not be recovered, the asset is monitored
 
by management through an established
 
process where
changes to significant assumptions such as prices,
 
volumes and future development plans are reviewed.
 
If, upon review, the sum of the undiscounted before-tax cash flows is less
 
than the carrying value of the
asset group, the carrying value is written down to
 
estimated fair value through additional
 
amortization or
depreciation provisions and reported as impairments
 
in the periods 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
 
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,
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.
 
89
 
 
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 and annually following updates to corporate
 
planning assumptions.
 
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 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).
 
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 10—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 in a purchase
 
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
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,
 
90
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. 2016-02, “Leases,” (ASC Topic 842) and its amendments,
beginning January 1, 2019.
 
ASC Topic 842 establishes comprehensive accounting and financial reporting
requirements for leasing arrangements, supersedes
 
the existing requirements in FASB ASC Topic 840,
“Leases” (ASC Topic 840), and requires lessees to recognize substantially
 
all lease assets and lease liabilities
on the balance sheet.
 
The provisions of ASC Topic 842 also modify the definition of a lease
 
and outline
requirements for recognition, measurement, presentation
 
and disclosure of leasing arrangements by
 
both
lessees and lessors.
 
 
We adopted ASC Topic
 
842 using the modified retrospective
 
approach and elected to utilize the Optional
Transition Method, which permits us to apply the provisions
 
of ASC Topic 842 to leasing arrangements
existing at or entered into after January 1, 2019,
 
and present in our financial statements comparative
 
periods
prior to January 1, 2019 under the historical
 
requirements of ASC Topic 840.
 
In addition, we elected to adopt
the package of optional transition-related practical
 
expedients, which among other things, allows us to
 
carry
forward certain historical conclusions reached
 
under ASC Topic 840 regarding lease identification,
classification, and the accounting treatment
 
of initial direct costs.
 
Furthermore, we elected not to record assets
and liabilities on our consolidated balance sheet
 
for new or existing lease arrangements
 
with terms of 12
months or less.
 
The primary impact of applying ASC Topic 842 is the initial recognition
 
of $
998
 
million of lease liabilities and
corresponding right-of-use assets on our consolidated
 
balance sheet as of January 1, 2019, for leases
 
classified
as operating leases under ASC Topic 840, as well as enhanced disclosure of our leasing
 
arrangements.
 
Our
accounting treatment for finance leases remains
 
unchanged.
 
In addition, there is no cumulative effect to
retained earnings or other components of equity
 
recognized as of January 1, 2019, and the adoption
 
of ASC
Topic 842 did not impact the presentation of our consolidated income statement
 
or statement of cash flows.
 
See Note 17—Non-Mineral Leases for additional
 
information related to the adoption of ASC Topic 842.
 
 
 
 
 
 
91
We adopted the provisions of FASB ASU No. 2018-02, “Reclassification of Certain Tax Effects from
Accumulated Other Comprehensive Income,”
 
beginning January 1, 2019.
 
The ASU allows a reclassification
from accumulated other comprehensive income
 
to retained earnings for stranded tax effects resulting
 
from the
Tax Cuts and Jobs Act, eliminating the stranded tax effects.
 
The cumulative effect to our consolidated balance
sheet at January 1, 2019 for the adoption of
 
ASU No. 2018-02 was as follows:
 
 
 
Millions of Dollars
December 31
ASU No. 2018-02
January 1
2018
Adjustments
2019
Equity
Accumulated other comprehensive loss
$
(6,063)
(40)
(6,103)
Retained earnings
34,010
40
34,050
For additional information regarding the impact of the adoption of ASU No. 2018-02, see
 
Note 20—Accumulated Other Comprehensive Loss.
 
 
Note 3—Variable Interest Entities
 
We hold variable interests in VIEs for which there are existing arrangements that provide
 
those entities with
additional forms of subordinated financial support.
 
However, as we are not considered the primary
beneficiary, these entities have not been consolidated in our financial statements.
 
Marine Well Containment Company, LLC (MWCC)
We have a
10
 
percent ownership interest in MWCC, and
 
it is accounted for as an equity method investment
because MWCC is a limited liability company
 
in which we are a founding member.
 
MWCC is considered a
VIE, as it has entered into arrangements that provide
 
it with additional forms of subordinated
 
financial support.
We are not the primary beneficiary and do not consolidate MWCC because we share
 
the power to govern the
business and operation of the company and to
 
undertake certain obligations that most
 
significantly impact its
economic performance with nine other unaffiliated
 
owners of MWCC.
 
Based on inputs related to the fair value of MWCC
 
observed in the second quarter of 2019, we reduced
 
the
carrying value of our equity method investment
 
in MWCC to $
30
 
million and recorded a before-tax
impairment of $
95
 
million which is included in the “Equity
 
in earnings of affiliates” line on our consolidated
income statement. For additional information
 
see Note 15—Fair Value Measurement.
 
At December 31, 2019,
the book value of our equity method investment
 
in MWCC was $
24
 
million. We have not provided any
financial support to MWCC other than amounts
 
previously contractually required. Unless we elect
 
otherwise,
we have no requirement to provide liquidity
 
or purchase the assets of MWCC.
Australia Pacific LNG Pty Ltd (APLNG)
We hold a
37.5
 
percent interest in APLNG, our joint venture
 
with Origin Energy and Sinopec. We are not the
primary beneficiary because we share, with
 
our joint venture partners, the power to direct
 
the key activities of
APLNG that most significantly impacts its
 
economic performance. Therefore, we do not consolidate
 
APLNG
and account for this entity as an equity method
 
investment.
 
As of December 31, 2019, we no longer have
certain guarantees that provide APLNG with additional
 
subordinated financial support. For additional
information see Note 12—Guarantees.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
92
Note 4—Inventories
Inventories at December 31 were:
Millions of Dollars
2019
2018
Crude oil and natural gas
$
472
432
Materials and supplies
554
575
$
1,026
1,007
 
 
Inventories valued on the LIFO basis totaled
 
$
286
 
million and $
292
 
million at December 31, 2019 and 2018,
respectively.
 
The estimated excess of current replacement
 
cost over LIFO cost of inventories was
approximately $
155
 
million and $
75
 
million at December 31, 2019 and December
 
31, 2018, respectively.
 
 
 
Note 5—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 are included in the “Cash Flows
From Investing Activities” section of our consolidated
 
statement of cash flows.
 
 
 
2019
Assets Held for Sale
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos for $
1.39
 
billion, plus customary adjustments, with an effective
 
date of January 1, 2019.
 
In addition, we will receive a payment of $
75
 
million upon final investment decision of
 
the Barossa
development project.
 
These subsidiaries hold our
37.5
 
percent interest in the Barossa Project and
 
Caldita
Field, our
56.9
 
percent interest in the Darwin LNG Facility and
 
Bayu-Undan Field, our
40
 
percent interest in
the Greater Poseidon Fields, and our
50
 
percent interest in the Athena Field.
 
The net carrying value is
approximately $
0.6
 
billion, which consisted primarily of $
1.2
 
billion of PP&E and $
0.3
 
billion of cash and
working capital, offset by $
0.7
 
billion of ARO and $
0.2
 
billion of deferred tax liabilities.
 
The assets met held
for sale criteria in the fourth quarter, and as of December 31, 2019
 
we had reclassified $
1.2
 
billion of PP&E to
“Prepaid expenses and other current assets” and $
0.7
 
billion of noncurrent ARO to “Other accruals”
 
on our
consolidated balance sheet.
 
The before-tax earnings associated with our
 
Australia-West subsidiaries were
$
372
 
million, $
364
 
million and $
317
 
million for the years ended December 31,
 
2019, 2018 and 2017,
respectively.
 
This transaction is expected to be completed
 
in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent.
 
Results of operations for the subsidiaries
 
to be sold are
reported within our Asia Pacific and Middle East
 
segment.
 
In the fourth quarter of 2019, we signed an agreement
 
to sell our interests in the Niobrara shale play
 
for $
380
million, plus customary adjustments,
 
and overriding royalty interests in certain
 
future wells.
 
To reduce the
carrying value to fair value, in the fourth quarter
 
of 2019, we recorded an impairment of $
379
 
million before-
tax for developed properties and exploration expenses
 
of $
7
 
million related to leasehold impairment of
undeveloped properties.
 
Our Niobrara interests to be sold have a net carrying
 
value of approximately $
390
million, which consisted primarily of $
426
 
million of PP&E, offset by $
34
 
million of noncurrent ARO.
 
The
assets met held for sale criteria in the fourth quarter, and as of December
 
31, 2019, we had reclassified $
426
million of PP&E to “Prepaid expenses and other
 
current assets” and $
34
 
million of noncurrent AROs to “Other
accruals” on our consolidated balance sheet.
 
The before-tax losses associated with our interests
 
in Niobrara,
including the $386 million of impairments noted
 
above, were $
372
 
million and $
12
 
million for the years ended
December 31, 2019 and 2017,
 
respectively.
 
The before-tax earnings associated with our interests
 
in Niobrara
for the year ended December 31, 2018 was $
35
 
million.
 
This transaction is subject to regulatory approval
 
and
other specific conditions precedent and is expected
 
to close in the first quarter of 2020.
 
The Niobrara results of
operations are reported within our Lower 48 segment.
 
 
 
93
 
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 are reported in
 
our Lower 48 segment.
 
See Note 15—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 were $
0.4
 
billion, $
0.9
 
billion and $
0.3
 
billion for the years ended December 31, 2019,
 
2018
and 2017,
 
respectively.
 
Results of operations for the U.K. are reported
 
within our Europe 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 and Middle East 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 are reported
 
within
our Lower 48 segment.
 
Planned Dispositions
In January 2020, we entered into an agreement to sell
 
our interests in certain non-core properties
 
in the Lower
48 segment for $
186
 
million, plus customary adjustments.
 
The assets met the held for sale criteria in
 
January
2020 and the transaction is expected to be completed
 
in the first quarter of 2020.
 
No gain or loss is anticipated
on the sale.
 
This disposition will not have a significant
 
impact on Lower 48 production.
 
 
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 impairments of $
87
million in 2018 and $
572
 
million in 2017 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 losses associated with our
 
interests in the Barnett,
including both the impairments and loss on disposition
 
noted above, were $
59
 
million and $
566
 
million for the
years 2018 and 2017, respectively.
 
The Barnett results of operations are included
 
in our Lower 48 segment.
 
 
94
 
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 interest in the Clair
Field, including the recognized gain, were $
748
 
million.
 
The before-tax loss associated with our interest
 
in the
Clair Field was $
0.4
 
million for 2017. Results of operations
 
for our interest in the Clair Field are reported
within our Europe and North Africa segment and
 
the Kuparuk Assets are 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.
 
2017
Assets Sold
On May 17, 2017, we completed the sale of our
 
50 percent nonoperated interest in the Foster
 
Creek Christina
Lake (FCCL) Partnership, as well as the majority
 
of our western Canada gas assets to Cenovus
 
Energy.
 
Consideration for the transaction was $
11.0
 
billion in cash after customary adjustments,
208
 
million Cenovus
Energy common shares and a five-year uncapped contingent
 
payment.
 
The value of the shares at closing was
$
1.96
 
billion based on a price of $
9.41
 
per share on the NYSE.
 
The contingent payment, calculated and paid
on a quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price
exceeds $52 CAD per barrel.
 
Contingent payments received during the five-year
 
period are reflected as “Gain
on dispositions” on our consolidated income statement.
 
We reported before-tax equity earnings associated
with FCCL of $
197
 
million for 2017.
 
We reported a before-tax loss of $
26
 
million for the western Canada gas
producing properties for 2017.
 
We recorded gains on dispositions for these contingent payments of $
114
million and $
95
 
million for the years 2019 and 2018, respectively.
 
 
At closing, the carrying value of our equity investment
 
in FCCL was $
8.9
 
billion.
 
The carrying value of our
interest in the western Canada gas assets was $
1.9
 
billion consisting primarily of $
2.6
 
billion of PP&E, partly
offset by AROs of $
585
 
million and approximately $
100
 
million of environmental and other accruals.
 
A gain
of $
2.1
 
billion was included in the “Gain on dispositions”
 
line on our consolidated income statement in 2017.
 
Both FCCL and the western Canada gas assets
 
were reported in our Canada segment.
 
 
For more information on the Canada disposition
 
and our investment in Cenovus Energy see Note 7—
Investment in Cenovus Energy, Note 15—Fair Value Measurement, and Note 20—Accumulated Other
Comprehensive Loss.
 
In July 2017, we completed the sale of our interests
 
in the San Juan Basin to an affiliate of Hilcorp Energy
 
 
 
 
 
 
 
 
 
 
 
 
 
 
95
Company for $
2.5
 
billion in cash after customary adjustments
 
and recognized a loss on disposition of
$
22
 
million.
 
The transaction includes a contingent payment of up to $300 million. The six-year contingent
payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly U.S. Henry
Hub price is at or above $3.20 per MMBTU.
 
In 2018, we recorded a gain on dispositions
 
for these contingent
payments of $
28
 
million.
 
No
 
contingent payments were recorded in 2019.
 
In the second quarter of 2017, we
recorded an impairment of $
3.3
 
billion to reduce the carrying value of our
 
interests in the San Juan Basin to
fair value.
 
At the time of disposition, the San Juan Basin
 
interests had a net carrying value of approximately
$
2.5
 
billion, consisting of $
2.9
 
billion of PP&E and $
406
 
million of liabilities, primarily AROs.
 
The before-
tax loss associated with our interests in the San Juan
 
Basin, including both the $3.3 billion impairment
 
and $22
million loss on disposition noted above, was $
3.2
 
billion for 2017.
 
The San Juan Basin results were reported
in our Lower 48 segment.
 
 
In September 2017, we completed the sale of our
 
interest in the Panhandle assets for $
178
 
million in cash after
customary adjustments and recognized a loss on
 
disposition of $
28
 
million.
 
At the time of the disposition, the
carrying value of our interest was $
206
 
million, consisting primarily of $
279
 
million of PP&E and $
72
 
million
of AROs.
 
Including the $28 million loss on disposition
 
noted above, we reported a before-tax loss for the
Panhandle properties of $
14
 
million for 2017.
 
The Panhandle results were reported in
 
our Lower 48 segment.
 
 
 
Note 6—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term
 
receivables at December 31 were:
Millions of Dollars
2019
2018
Equity investments
$
8,234
9,005
Loans and advances—related parties
219
335
Long-term receivables
243
238
Long-term investments in debt securities
133
-
Other investments
77
86
$
8,906
9,664
 
 
Equity Investments
Affiliated companies in which we had a significant
 
equity investment at December 31, 2019, 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
2019
2018
2017
Revenues
$
11,310
11,654
11,554
Income (loss) before income taxes
3,726
3,660
(2,875)
Net income (loss)
3,085
3,244
(1,431)
 
 
 
 
 
 
 
 
96
Summarized 100 percent balance sheet information
 
for equity method investments in affiliated
 
companies,
 
combined, was as follows:
Millions of Dollars
2019
2018
Current assets
$
3,289
3,285
Noncurrent assets
38,905
41,563
Current liabilities
2,603
2,625
Noncurrent liabilities
22,168
23,874
 
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, 2019, retained earnings included
 
$
32
 
million related to the undistributed earnings
 
of
affiliated companies.
 
Dividends received from affiliates were $
1,378
 
million, $
1,226
 
million and $
605
 
million
in 2019, 2018 and 2017,
 
respectively.
 
 
APLNG
 
APLNG is focused on CBM production from the
 
Bowen and Surat basins in Queensland, Australia,
 
to supply
the domestic gas market and on LNG processing
 
and export sales.
 
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.
 
At December 31, 2019, all amounts have been
 
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, 2019, a balance of $
6.7
 
billion was outstanding on the facilities.
 
See Note 12—Guarantees,
for additional information.
 
 
 
97
During the first half of 2017, the outlook for crude
 
oil prices deteriorated, and as a result of significantly
reduced price outlooks, the estimated fair
 
value of our investment in APLNG declined to
 
an amount below
carrying value.
 
Based on a review of the facts and circumstances
 
surrounding this decline in fair value, we
concluded in the second quarter of 2017 the impairment
 
was other than temporary under the guidance of
 
FASB
ASC Topic 323, “Investments—Equity Method and Joint Ventures,” and the recognition of an impairment of
our investment to fair value was necessary.
 
Accordingly, we recorded a noncash $
2,384
 
million, before- and
after-tax impairment in our second quarter 2017
 
results.
 
Fair value was estimated based on an internal
discounted cash flow model using estimated
 
future production, an outlook of future prices
 
from a combination
of exchanges (short-term) and pricing service
 
companies (long-term), costs, 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.
 
The impairment was included in the “Impairments”
 
line on our consolidated
income statement.
 
At December 31, 2019, the carrying value of
 
our equity method investment in APLNG was $
7,228
 
million.
 
The historical cost basis of our
37.5
 
percent share of net assets on the books
 
of APLNG was $
6,751
 
million,
resulting in a basis difference of $
477
 
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 2019,
 
2018 and 2017 was after-tax
expense of $
36
 
million, $
44
 
million and $
100
 
million, respectively, representing the amortization of this basis
difference on currently producing licenses.
 
Distributions from APLNG commenced in
 
April 2018.
 
FCCL
FCCL Partnership, a Canadian upstream 50/50 general
 
partnership with Cenovus Energy Inc., produces
bitumen in the Athabasca oil sands in northeastern
 
Alberta and sells the bitumen blend.
 
Cenovus is the
operator and managing partner of FCCL.
 
 
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.
 
Financial information presented
within this footnote includes our historical
 
interest up to the date of sale.
 
For additional information on the
Canada disposition and our investment in Cenovus
 
Energy, see Note 5—Asset Acquisitions and Dispositions
and Note 7—Investment in Cenovus Energy.
 
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 $
335
 
million as described below under “Loans and
 
Long-
Term Receivables.”
 
At December 31, 2019, the book value of our equity
 
method investment in QG3,
excluding the project financing, was $
797
 
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 5—Asset
Acquisitions and Dispositions.
 
 
 
98
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, 2019, significant loans to affiliated
 
companies include $335 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.”
 
 
 
Note 7—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.
 
See Note 5—Asset Acquisitions and Dispositions,
 
for
additional information on the Canada disposition.
 
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.
 
 
Our investment on our consolidated balance sheet
 
as of December 31, 2019, is carried
 
at fair value of $
2.11
billion, reflecting the closing price of Cenovus
 
Energy shares on the NYSE of $
10.15
 
per share, an increase of
$
649
 
million from $
1.46
 
billion at December 31, 2018.
 
The increase in fair value represents the
 
net unrealized
gain recorded within the “Other income” line of
 
our consolidated income statement for
 
the year ended
December 31, 2019 relating to the shares held
 
at the reporting date.
 
See Note 15—Fair Value Measurement
and Note 22—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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
99
Note 8—Suspended Wells and Other Exploration Expenses
The following table reflects the net changes in suspended
 
exploratory well costs during 2019, 2018 and 2017:
Millions of Dollars
2019
2018
2017
Beginning balance at January 1
$
856
853
1,063
Additions pending the determination of proved reserves
239
140
118
Reclassifications to proved properties
(11)
(37)
(66)
Sales of suspended wells
(54)
(93)
-
Charged to dry hole expense
(10)
(7)
(262)
Ending balance at December 31
 
$
1,020
*
856
853
*Includes $
313
 
million of assets held for sale in Australia.
 
 
The following table provides an aging of suspended
 
well balances at December 31:
Millions of Dollars
2019
2018
2017
Exploratory well costs capitalized for a period
 
of one year or less
$
206
145
67
Exploratory well costs capitalized for a period
 
greater than one year
814
711
786
Ending balance
$
1,020
*
856
853
Number of projects with exploratory well costs
 
capitalized for a
period greater than one year
23
24
23
*Includes $313 million of assets held for sale in Australia.
 
 
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, 2019:
Millions of Dollars
Suspended Since
Total
2016–2018
2013–2015
2004–2012
Greater Poseidon—Australia
(2)(3)
177
-
157
20
NPRA—Alaska
(1)
149
111
38
-
Barossa/Caldita—Australia
(2)(3)
136
59
-
77
Surmont—Canada
(1)
118
6
55
57
Middle Magdalena Basin—Colombia
(1)
68
-
68
-
Narwhal Trend—Alaska
(1)
52
52
-
-
Kamunsu East—Malaysia
(2)
19
-
19
-
NC 98—Libya
(2)
15
-
11
4
WL4-00—Malaysia
(2)
17
17
-
-
Other of $10 million or less each
(1)(2)
63
20
26
17
Total
$
814
265
374
175
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
(3)Assets held for sale as of December 31, 2019.
 
 
 
 
 
 
 
 
 
 
 
100
Other Exploration Expenses
In February 2017, we reached a settlement
 
agreement on our contract for the Athena drilling
 
rig, initially
secured for our four-well commitment program
 
in Angola.
 
As a result of the cancellation, we recognized
 
a
before-tax charge of $
43
 
million net in the first quarter of 2017.
 
These charges are included in the
“Exploration expenses” line on our consolidated income
 
statement and in our Other International segment
 
in
2017.
 
In 2019, we recorded before-tax dry hole expenses
 
of $
111
 
million due to our decision to discontinue
exploration activities in the Central Louisiana Austin
 
Chalk trend.
 
These charges are included in our Lower 48
segment and in the “Exploration expenses” line
 
on our consolidated income statement.
 
See Note 9—
Impairments for additional information on our
 
decision to discontinue these exploration activities.
 
 
Note 9—Impairments
During 2019, 2018 and 2017, we recognized the
 
following before-tax impairment charges:
Millions of Dollars
2019
2018
2017
Alaska
$
-
20
180
Lower 48
402
63
3,969
Canada
2
9
22
Europe and North Africa
1
(79)
46
Asia Pacific and Middle East
-
14
2,384
$
405
27
6,601
 
 
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 5—Asset Acquisitions and
Dispositions,
 
for additional information on this disposition.
 
The charges discussed below, within this section, are included in the “Exploration
 
expenses” line on our
consolidated income statement and are not reflected
 
in the table above.
 
In our Lower 48 segment, we recorded a before-tax impairment
 
of $
141
 
million for the associated carrying
value of capitalized undeveloped leasehold costs
 
due to our decision to discontinue exploration
 
activities
related to our Central Louisiana Austin Chalk
 
acreage.
 
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 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 have ceased production and
 
were impaired in prior years,
partly offset by an increased ARO estimate on a field
 
in Norway which has ceased production.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101
2017
 
In Alaska, we recorded impairments of $
180
 
million primarily for the associated PP&E
 
carrying value of our
small interest in the Point Thomson unit.
 
 
In the Lower 48, we recorded impairments
 
of $
3,969
 
million primarily due to certain developed
 
properties
which were written down to fair value less costs
 
to sell.
 
See Note 5—Asset Acquisitions and Dispositions, for
additional information on our dispositions.
 
 
In Canada, we recorded impairments of $
22
 
million primarily due to cancelled projects.
 
In Europe and North Africa, we recorded impairments
 
of $
46
 
million primarily due to reduced volume
forecasts for a field in the U.K. and restructured ownership
 
and a change in commercial premises for a gas
processing plant in Norway, partly offset by decreased ARO estimates on fields at or
 
nearing the end of life
which were impaired in prior years.
 
In Asia Pacific and Middle East, we recorded impairments
 
of $
2,384
 
million, including the impairment of our
APLNG investment.
 
For more information, see the “APLNG”
 
section of Note 6—Investments, Loans and
Long-Term Receivables.
 
 
The charges discussed below, within this section, are included in the “Exploration
 
expenses” line on our
consolidated income statement and are not reflected
 
in the table above.
 
In our Lower 48 segment, we recorded a before-tax impairment
 
of $
51
 
million for the associated carrying
value of capitalized undeveloped leasehold costs
 
of Shenandoah in deepwater Gulf of Mexico
 
following the
suspension of appraisal activity by the operator.
 
Additionally, we recorded a $
38
 
million before-tax
impairment for mineral assets primarily
 
due to plan of development changes.
 
 
Note 10—Asset Retirement Obligations and Accrued
 
Environmental Costs
 
Asset retirement obligations and accrued environmental
 
costs at December 31 were:
Millions of Dollars
2019
2018
Asset retirement obligations
$
6,206
7,908
Accrued environmental costs
171
178
Total asset retirement obligations and accrued environmental costs
6,377
8,086
Asset retirement obligations and accrued environmental
 
costs due within one year*
(1,025)
(398)
Long-term asset retirement obligations and accrued
 
environmental costs
$
5,352
7,688
*Classified as a current liability on the balance sheet under “Other accruals.” $
741
 
million relates to assets which are held for sale as of
December 31, 2019. For additional information see Note 5—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.
 
 
 
 
 
 
 
 
 
 
 
 
102
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 2019 and 2018, our overall ARO changed
 
as follows:
Millions of Dollars
2019
2018
Balance at January 1
$
7,908
7,798
Accretion of discount
322
348
New obligations
155
657
Changes in estimates of existing obligations
50
(266)
Spending on existing obligations
(229)
(228)
Property dispositions
(1,920)
(161)
Foreign currency translation
(80)
(240)
Balance at December 31
$
6,206
7,908
 
 
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2019 and 2018, were $
171
 
million and $
178
 
million,
respectively.
 
 
We had accrued environmental costs of $
112
 
million and $
100
 
million at December 31, 2019 and 2018,
respectively, related to remediation activities in the U.S. and Canada.
 
We had also accrued in Corporate and
Other $
47
 
million and $
67
 
million of environmental costs associated
 
with sites no longer in operation at
December 31, 2019 and 2018, respectively.
 
In addition, $
12
 
million and $
11
 
million were included at both
December 31, 2019 and 2018, 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 $
97
 
million at December 31, 2019.
 
The expected future undiscounted payments
 
related to the
portion of the accrued environmental costs that
 
have been discounted are: $
10
 
million in 2020, $
7
 
million in
2021, $
10
 
million in 2022, $
3
 
million in 2023, $
2
 
million in 2024, and $
108
 
million for all future years
after 2024.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
103
Note 11—Debt
Long-term debt at December 31 was:
Millions of Dollars
2019
2018
9.125% Debentures due 2021
$
123
123
8.20% Debentures due 2025
134
134
8.125% Notes due 2030
390
390
7.9% Debentures due 2047
60
60
7.8% Debentures due 2027
203
203
7.65% Debentures due 2023
78
78
7.40% Notes due 2031
500
500
7.375% Debentures due 2029
92
92
7.25% Notes due 2031
500
500
7.20% Notes due 2031
575
575
7% Debentures due 2029
200
200
6.95% Notes due 2029
1,549
1,549
6.875% Debentures due 2026
67
67
6.50% Notes due 2039
2,750
2,750
5.951% Notes due 2037
645
645
5.95% Notes due 2036
500
500
5.95% Notes due 2046
500
500
5.90% Notes due 2032
505
505
5.90% Notes due 2038
600
600
4.95% Notes due 2026
1,250
1,250
4.30% Notes due 2044
750
750
4.15% Notes due 2034
246
246
3.35% Notes due 2024
426
426
3.35% Notes due 2025
199
199
2.4% Notes due 2022
329
329
Floating rate notes due 2022 at
2.81
% –
3.58
% during 2019 and
2.32
% –
3.52
% during 2018
500
500
Industrial Development Bonds due 2035 at
1.08
% –
2.45
% during 2019 and
0.95
% –
1.86
% during 2018
18
18
Marine Terminal Revenue Refunding Bonds due 2031 at
1.08
% –
2.45
% during
 
2019 and
0.88
% –
1.95
% during 2018
265
265
Other
17
17
Debt at face value
13,971
13,971
Finance leases
720
777
Net unamortized premiums, discounts and
 
debt issuance costs
204
220
Total debt
14,895
14,968
Short-term debt
(105)
(112)
Long-term debt
$
14,790
14,856
 
104
Maturities of long-term borrowings, inclusive
 
of net unamortized premiums and discounts,
 
in 2020 through
2024 are: $
105
 
million, $
235
 
million, $
940
 
million, $
198
 
million and $
548
 
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.
 
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.
 
We have a $
6.0
 
billion commercial paper program, which
 
is primarily a funding source for short-term
 
working
capital needs.
 
Commercial paper maturities are generally
 
limited to
90 days
.
 
We had no commercial paper
outstanding in programs in place at December
 
31, 2019 or December 31, 2018.
 
We had
no
 
direct outstanding
borrowings or letters of credit under the revolving
 
credit facility at December 31, 2019 or December
 
31, 2018.
 
Since we had
no
 
commercial paper outstanding and had issued
 
no letters of credit, we had access to
$
6.0
 
billion in borrowing capacity under our revolving
 
credit facility at December 31, 2019.
 
At both December 31, 2019 and 2018, we had
 
$
283
 
million of certain variable rate demand
 
bonds (VRDBs)
outstanding which mature
 
in 2035.
 
The VRDBs are redeemable at the option of the
 
bondholders on any
business day.
 
If they are ever redeemed, we intend to refinance
 
on a long-term basis, therefore, the VRDBs are
included in the “Long-term debt” line on our consolidated
 
balance sheet.
 
 
For additional information on Finance Leases,
 
see Note 17
Non-Mineral Leases.
 
 
 
Note 12—Guarantees
 
At December 31, 2019, we were liable for certain
 
contingent obligations under various contractual
arrangements as described below.
 
We recognize a liability, at inception, for the fair value of our obligation as
a guarantor for newly issued or modified guarantees.
 
Unless the carrying amount of the liability
 
is noted
below, we have not recognized a liability because the fair value of the obligation
 
is immaterial.
 
In addition,
unless otherwise stated, we are not currently
 
performing with any significance under the
 
guarantee and expect
future performance to be either immaterial
 
or have only a remote chance of occurrence.
 
APLNG Guarantees
At December 31, 2019, 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
2019 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 is
11 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, 2019, the carrying value
 
of this guarantee is approximately $
14
million.
 
 
 
105
 
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 up to
22 years
.
 
Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated
 
to be $
780
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 up to
26 years or the life of the venture
.
 
As of December 31, 2019, we were released from
 
certain of these
guarantees considered subordinated financial
 
support to APLNG.
 
Our remaining maximum potential
amount of future payments related to the remaining
 
guarantees is approximately $
60
 
million and
would become payable if APLNG does not perform.
 
Other Guarantees
 
We have other guarantees with maximum future potential payment amounts totaling
 
approximately
$
820
 
million, which consist primarily of
 
guarantees of the residual value of leased office buildings,
 
guarantees
of the residual value of leased corporate aircraft,
 
and a guarantee for our portion of a joint
 
venture’s project
finance reserve accounts.
 
These guarantees have remaining terms of up to
three years
and would become
payable if, upon sale, certain asset values are lower
 
than guaranteed amounts, business conditions
 
decline at
guaranteed entities, or as a result of nonperformance
 
of contractual terms by guaranteed parties.
 
 
In conjunction with the disposition of our two
 
U.K. subsidiaries to Chrysaor E&P Limited,
 
we will temporarily
continue to support various guarantees and letters
 
of credit which were provided for the benefit of entities
 
that
are now affiliates of Chrysaor E&P Limited.
 
Our maximum potential payment exposure under
 
these
obligations is approximately $
100
 
million.
 
Chrysaor E&P Limited has agreed to fully
 
indemnify
ConocoPhillips for any losses suffered by us related to
 
these obligations.
 
 
Indemnifications
Over the years, we have entered into agreements to
 
sell ownership interests in certain corporations,
 
joint
ventures and assets that gave rise to qualifying
 
indemnifications.
 
These agreements include indemnifications
for taxes, environmental liabilities, employee claims
 
and litigation.
 
The terms of these indemnifications vary
greatly.
 
The majority of these indemnifications are related
 
to environmental issues, the term is generally
indefinite and the maximum amount of future payments
 
is generally unlimited.
 
The carrying amount recorded
for these indemnifications at December 31, 2019,
 
was approximately $
80
 
million.
 
We amortize the
indemnification liability over the relevant time
 
period, 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.
 
Included in the
recorded carrying amount at December 31, 2019,
 
were approximately $
30
 
million of environmental accruals
for known contamination that are included in
 
the “Asset retirement obligations and accrued
 
environmental
costs” line on our consolidated balance sheet.
 
For additional information about environmental
 
liabilities, see
Note 13—Contingencies and Commitments.
 
 
106
Note 13—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
minimum of the range is accrued.
 
We do not reduce these liabilities for potential insurance or third-party
recoveries.
 
If applicable, we accrue receivables for probable
 
insurance or other third-party recoveries.
 
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 19—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
 
107
not reduced these accruals for possible insurance recoveries.
 
In the future, we may be involved in additional
environmental assessments, cleanups and proceedings.
 
See Note 10—Asset Retirement Obligations and
Accrued Environmental Costs, for a summary of our
 
accrued environmental liabilities.
 
Legal Proceedings
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.
 
Other Contingencies
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, 2019, we had performance
 
obligations secured by letters of credit
 
of
$
277
 
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.
 
 
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 failed to
 
cure its breach.
 
As
a result, ConocoPhillips has resumed legal enforcement
 
actions.
 
ConocoPhillips has ensured that the
 
108
settlement and any actions 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 $
55
 
million 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
 
Ve
 
nezuela.
 
In February 2017, the ICSID Tribunal unanimously awarded Burlington
 
Resources, Inc., a wholly owned
subsidiary of ConocoPhillips, $
380
 
million for Ecuador’s unlawful expropriation of
 
Burlington’s investment in
Blocks 7 and 21, in breach of the U.S.-Ecuador
 
Bilateral Investment Treaty.
 
The tribunal also issued a
separate decision finding Ecuador to be entitled
 
to $
42
 
million for environmental and infrastructure
counterclaims.
 
In December 2017, Burlington and Ecuador
 
entered into a settlement agreement by which
Ecuador paid Burlington $
337
 
million in two installments.
 
The first installment of $
75
 
million was paid in
December 2017, and the second installment
 
of $
262
 
million was paid in April 2018.
 
The settlement included
an offset for the counterclaims decision, of which Burlington
 
is entitled to a contribution from Perenco
Ecuador Limited, its co-venturer and consortium
 
operator, pursuant to a joint and several liability provision in
the JOA.
 
In September 2019, a separate ICSID Tribunal issued an award
 
in the Perenco arbitration, ordering
Perenco to pay an additional $
54
 
million to Ecuador for its environmental counterclaim.
 
Burlington and
Perenco will reconcile their shares of the environmental
 
and infrastructure counterclaims according
 
to their
JOA participating interests, and we expect Burlington’s share will be immaterial.
 
In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips
 
Senegal B.V.
 
in connection
with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016.
 
In
February 2020, the ICC Tribunal issued an award dismissing
 
FAR Ltd.’s
 
claims in the arbitration.
 
In late 2017, ConocoPhillips (U.K.) Limited
 
(CPUKL) initiated United Nations Commission
 
on International
Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral
Investment Treaty relating to a tax dispute arising from the
 
2012 sale of ConocoPhillips (U.K.) Cuu Long
Limited and ConocoPhillips (U.K.) Gama Limited.
 
The parties entered into a settlement agreement
 
in October
2019, and the arbitration was dismissed in
 
December 2019 as a result of this agreement.
 
In 2017 and 2018, cities, counties, and a state
 
government in California, New York, Washington, Rhode Island
and Maryland, as well as the Pacific Coast Federation
 
of Fishermen’s Association, Inc., have filed lawsuits
against oil and gas companies, including ConocoPhillips,
 
seeking compensatory damages and equitable
 
relief
to abate alleged climate change impacts.
 
ConocoPhillips is vigorously defending against
 
these lawsuits.
 
The
lawsuits brought by the Cities of San Francisco,
 
Oakland and New York have been dismissed by the district
courts and appeals are pending.
 
Lawsuits filed by other cities and counties
 
in California and Washington are
currently stayed pending resolution of the appeals
 
brought by the Cities of San Francisco and
 
Oakland to the
U.S. Court of Appeals for the Ninth Circuit.
 
Lawsuits filed in Maryland and Rhode Island
 
are proceeding in
state court while rulings in those matters, on the
 
issue of whether the matters should proceed
 
in state or federal
court, are on appeal to the U.S. Court of Appeals
 
for the Fourth Circuit and First Circuit,
 
respectively.
 
Several Louisiana parishes and individual landowners
 
have filed lawsuits against oil and gas companies,
including ConocoPhillips, seeking compensatory
 
damages in connection with historical oil
 
and gas operations
in Louisiana.
 
All parish lawsuits are stayed pending an appeal
 
to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or
 
state court.
 
ConocoPhillips will vigorously defend against
these lawsuits.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
109
 
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:
2020—$
7
 
million; 2021—$
7
 
million; 2022—$
7
 
million; 2023—$
7
 
million; 2024—$
7
 
million; and 2025 and
after—$
57
 
million.
 
Total payments under the agreements were $
25
 
million in 2019, $
39
 
million in 2018 and
$
43
 
million in 2017.
 
 
Note 14—Derivative and Financial Instruments
 
We use futures, forwards, swaps and options in various markets to meet our customer
 
needs and capture
market opportunities.
 
Our commodity business primarily consists of
 
natural gas, crude oil, bitumen, LNG and
NGLs.
 
 
Our 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 use
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
2019
2018
Assets
Prepaid expenses and other current assets
$
288
410
Other assets
34
40
Liabilities
Other accruals
283
370
Other liabilities and deferred credits
28
30
 
 
The gains (losses) from commodity derivatives
 
incurred, and the line items where they appear
 
on our
consolidated income statement were:
Millions of Dollars
2019
2018
2017
Sales and other operating revenues
$
141
45
77
Other income
4
7
-
Purchased commodities
(118)
(41)
(61)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
110
The table below summarizes our material net exposures
 
resulting from outstanding commodity
 
derivative
contracts:
Open Position
Long/(Short)
2019
2018
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
(5)
(17)
Basis
(23)
(1)
 
 
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.
 
We do not elect hedge
accounting on our foreign currency exchange
 
derivatives.
 
The following table presents the gross fair values
 
of our foreign currency exchange derivatives,
 
excluding
collateral, and the line items where they appear
 
on our consolidated balance sheet:
Millions of Dollars
2019
2018
Assets
Prepaid expenses and other current assets
$
1
7
Liabilities
Other accruals
20
6
Other liabilities and deferred credits
8
-
 
 
The losses from foreign currency exchange derivatives
 
incurred and the line item where they appear
 
on our
consolidated income statement were:
Millions of Dollars
2019
2018
2017
Foreign currency transaction losses
$
16
1
13
 
We had the following net notional position of outstanding foreign currency exchange
 
derivatives:
In Millions
Notional Currency
2019
2018
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy British pound
USD
-
805
Sell British pound, buy other currencies*
GBP
-
21
Buy British pound, sell euro
GBP
4
-
Sell Canadian dollar, buy U.S. dollar
CAD
1,337
1,242
*Primarily euro and Norwegian krone.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
111
In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion
CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar.
The collar expired during the second quarter of 2019 and we entered into new 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.
 
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.
 
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:
 
 
 
 
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
2019
2018
2019
2018
Cash
$
759
876
Demand Deposits
1,483
-
-
-
Time Deposits
Remaining maturities from 1 to 90 days
2,030
3,509
1,395
-
Remaining maturities from 91 to 180 days
-
-
465
-
Commercial Paper
Remaining maturities from 1 to 90 days
413
229
1,069
248
U.S. Government Obligations
Remaining maturities from 1 to 90 days
394
1,301
-
-
$
5,079
5,915
2,929
248
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
112
The following table reflects our investments
 
in debt securities classified as available
 
for sale at December 31,
2019 which are carried at fair value:
Millions of Dollars
Carrying Amount
Cash and
Cash
Equivalents
Short-Term
Investments
Investments
and Long-
Term
Receivables
Corporate Bonds
Remaining maturities within one year
$
1
59
-
Remaining maturities greater than one year through
 
five years
-
-
99
Commercial Paper
Remaining maturities within one year
8
30
-
U.S. Government Obligations
Remaining maturities within one year
-
10
-
Remaining maturities greater than one year through
 
five years
-
-
15
Asset-backed Securities
Remaining maturities greater than one year through
 
five years
-
-
19
$
9
99
133
 
The following table summarizes the amortized
 
cost basis and fair value of investments in
 
debt securities
classified as available for sale at December 31,
 
2019:
Millions of Dollars
Amortized Cost
Basis
Fair Value
Major Security Type
Corporate bonds
$
159
159
Commercial paper
38
38
U.S. government obligations
25
25
Asset-backed securities
19
19
$
241
241
 
Gross unrealized gains and gross unrealized losses
 
included in other comprehensive income related
 
to
investments in debt securities classified as available
 
for sale as of December 31, 2019, were negligible.
 
There were no other-than-temporary impairments
 
recognized in earnings or in other comprehensive
 
income
during the year ended December 31, 2019.
 
Gross realized gains and gross realized losses
 
included in earnings from sales and redemptions
 
of investments
in debt securities classified as available for sale
 
during the year ended December 31, 2019,
 
were negligible.
 
The cost of securities sold and redeemed is determined
 
using the specific identification method.
 
113
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
 
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.
 
We do not generally require collateral to limit the exposure to loss;
however, we will sometimes use letters of credit, prepayments
 
and 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, 2019 and
 
December 31, 2018, was $
79
 
million and $
62
 
million,
respectively.
 
For these instruments,
no collateral
 
was posted as of December 31, 2019 or December 31,
 
2018.
 
If our credit rating had been downgraded below
 
investment grade on December 31, 2019,
 
we would be
required to post $
76
 
million of additional collateral, either with
 
cash or letters of credit.
 
Note 15—Fair Value Measurement
 
We carry a portion of our assets and liabilities at fair value that are measured at a 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
corroborated market data is no longer available.
 
Transfers occur at the end of the reporting period.
 
There were
no material transfers in or out of Level 1 during
 
2019 or 2018.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
114
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair
 
value on a recurring basis primarily include
 
our investment in
Cenovus Energy 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, and
asset-backed securities 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, 2019
December 31, 2018
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investment in Cenovus Energy
$
2,111
-
-
2,111
1,462
-
-
1,462
Investments in debt securities
25
216
-
241
Commodity derivatives
172
114
36
322
236
181
33
450
Total assets
$
2,308
330
36
2,674
1,698
181
33
1,912
Liabilities
Commodity derivatives
$
174
115
22
311
225
145
30
400
Total liabilities
$
174
115
22
311
225
145
30
400
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
115
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, 2019
Assets
$
322
3
319
193
126
4
122
Liabilities
311
4
307
193
114
12
102
December 31, 2018
Assets
$
450
9
441
280
161
-
161
Liabilities
400
4
396
280
116
10
106
At December 31, 2019 and December 31, 2018,
 
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, 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
Year
 
ended December 31, 2018
Net PP&E (held for sale)
 
March 31, 2018
$
250
-
-
250
44
 
September 30, 2018
201
201
-
-
43
 
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 each asset was
 
determined by its negotiated selling price (Level
 
1) or information gathered during marketing
 
efforts (Level 3).
 
For additional information see Note 5—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.
 
During 2019, investments using Level 1 inputs
 
were written down to fair value, less costs to
 
sell,
 
 
 
 
 
 
 
 
 
 
 
 
 
116
determined by negotiated selling prices.
 
For additional information, see Note 5—Asset
 
Acquisitions and
Dispositions.
 
During 2019, an investment using Level 2 inputs
 
was determined to have a fair value below its
carrying value, and was written down to fair value.
 
For additional information, see Note 3—Variable Interest
Entities.
 
 
 
 
Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial
 
instruments:
 
 
Cash and cash equivalents and short-term investments:
 
The carrying amount reported on the balance
sheet approximates fair value.
 
For those investments classified as available
 
for sale debt securities,
the carrying amount reported on the balance sheet
 
is fair value.
 
Accounts and notes receivable (including long-term
 
and related parties): The carrying amount
reported on the balance sheet approximates fair
 
value.
 
The valuation technique and methods used to
estimate the fair value of the current portion
 
of fixed-rate related party loans is consistent
 
with Loans
and advances—related parties.
 
Investment in Cenovus Energy shares: See Note 7—Investment
 
in Cenovus Energy for a discussion of
the carrying value and fair value of our investment
 
in Cenovus Energy 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 14—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 6—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.
 
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
2019
2018
2019
2018
Financial assets
Investment in Cenovus Energy
$
2,111
1,462
2,111
1,462
Commodity derivatives
125
170
125
170
Investments in debt securities
241
-
241
-
Total loans and advances—related parties
339
468
339
468
Financial liabilities
Total debt, excluding finance leases
14,175
14,191
18,108
16,147
Commodity derivatives
106
110
106
110
 
 
Commodity Derivatives
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.
 
At
December 31, 2018, commodity derivative assets
 
and liabilities are presented net with
no
 
obligations to return
cash collateral and $
10
 
million of rights to reclaim cash collateral,
 
respectively.
 
 
 
 
 
 
 
 
 
 
 
 
 
117
Note 16—Equity
Common Stock
The changes in our shares of common stock, as categorized
 
in the equity section of the balance sheet,
 
were:
Shares
2019
2018
2017
Issued
Beginning of year
1,791,637,434
1,785,419,175
1,782,079,107
Distributed under benefit plans
4,014,769
6,218,259
3,340,068
End of year
1,795,652,203
1,791,637,434
1,785,419,175
Held in Treasury
Beginning of year
653,288,213
608,312,034
544,809,771
Repurchase of common stock
57,495,601
44,976,179
63,502,263
End of year
710,783,814
653,288,213
608,312,034
 
 
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, 2019 or 2018.
 
Noncontrolling Interests
 
At December 31, 2019 and 2018, we had $
69
 
million and $
125
 
million outstanding, respectively, of equity in
less-than-wholly owned consolidated subsidiaries
 
held by noncontrolling interest owners.
 
For both periods,
the amounts were related to the Darwin LNG
 
and Bayu-Darwin Pipeline operating joint
 
ventures we control.
 
Repurchase of Common Stock
As of December 31, 2019, we had announced a total
 
authorization to repurchase $
15
 
billion of our common
stock.
 
Repurchase of shares began in November 2016,
 
and totaled
168,553,141
 
shares at a cost of $
9,625
million, through December 31, 2019.
 
In February 2020, we announced that the
 
Board of Directors approved
an increase to our repurchase authorization
 
from $15 billion to $
25
 
billion, to support our plan for future share
repurchases.
 
 
 
Note 17—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 12—Guarantees.
 
There are no significant restrictions
imposed on us by the lease agreements with regard
 
to dividends, asset dispositions or borrowing
 
ability.
 
 
118
Certain arrangements may contain both lease and
 
non-lease components and we determine
 
if an arrangement is
or contains a lease at contract inception.
 
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.
 
As of December 31, 2018, $
420
million of finance lease assets (net of accumulated
 
DD&A) and $
688
 
million of finance lease liabilities were
recorded on our consolidated balance sheet
 
associated with these leases.
 
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.
 
 
In connection with our adoption of ASC Topic 842, we have recorded on our
 
consolidated balance sheet $
57
million of operating leases executed by investee
 
companies accounted for under the proportionate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
119
consolidation method of accounting on a proportional
 
basis consistent with our ownership interest
 
in the
investee company.
 
 
The following tables summarize the finance leases
 
amounts that were reflected on our consolidated
 
balance
sheet as of December 31, 2018, the operating
 
leases impact of adopting ASC Topic 842, and the right-of-use
asset and lease liability balances reflected for both
 
operating and finance leases on our consolidated
 
balance
sheet as of December 31, 2019:
 
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
Amounts recognized in line items in our Consolidated
Balance Sheet upon adoption of ASC Topic 842
Right-of-Use Assets
Properties, plants and equipment
Gross
$
1,044
Accumulated depreciation, depletion and amortization
(550)
Net properties, plants and equipment as of December
 
31, 2018
$
494
Adoption of ASC Topic 842 as of January 1, 2019
$
998
Lease Liabilities
Short-term debt
$
79
Long-term debt
698
Total finance leases debt as of December 31, 2018
$
777
Adoption of ASC Topic 842 as of January 1, 2019
$
998
Amounts recognized in line items in our Consolidated
Balance Sheet at December 31, 2019
Right-of-Use Assets
Properties, plants and equipment
Gross
$
1,039
Accumulated depreciation, depletion and amortization
(649)
Net properties, plants and equipment
*
$
390
Prepaid expenses and other current assets
$
40
Other assets
896
 
* Includes proportionately consolidated finance lease assets (net of
 
accumulated depreciation, depletion and amortization) of $
335
 
million.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
120
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
Lease Liabilities
Short-term debt
*
$
87
Other accruals
$
347
Long-term debt
*
633
Other liabilities and deferred credits
585
Total lease liabilities
$
932
$
720
 
*
Short-term debt and long-term debt include proportionately consolidated finance
 
lease liabilities of $
56
 
million and $
579
 
million, respectively.
 
 
The following table summarizes our lease costs
 
for 2019:
Millions of Dollars
2019
Lease Cost
*
Operating lease cost
$
341
Finance lease cost
Amortization of right-of-use assets
99
Interest on lease liabilities
37
Short-term lease cost
**
77
Total lease cost
***
$
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.
 
Our future short-term lease commitments amount to $
31
 
million, of
 
which $
18
 
million is related to leases whose terms have not yet commenced
 
as of December 31, 2019.
***Variable lease cost and sublease income are immaterial for the period presented and therefore are not included in the table above.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
121
The following table summarizes the lease terms
 
and discount rates:
December 31, 2019
Lease Term and Discount Rate
Weighted-average term (years)
Operating leases
5.19
Finance leases
8.70
Weighted-average discount rate (percent)
Operating leases
3.10
Finance leases
5.53
The following table summarizes other lease information
 
for 2019:
Millions of Dollars
2019
Other Information
*
Cash paid for amounts included in the measurement
 
of lease liabilities
Operating cash flows from operating leases
$
203
Operating cash flows from finance leases
27
Financing cash flows from finance leases
81
Right-of-use assets obtained in exchange for
 
operating lease liabilities
$
499
Right-of-use assets obtained in exchange for
 
finance lease liabilities
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, 2019:
Millions of Dollars
Operating
Leases
Finance
 
Leases
Maturity of Lease Liabilities
2020
$
348
120
2021
247
104
2022
130
102
2023
82
88
2024
63
84
Remaining years
149
382
Total
*
1,019
880
Less: portion representing imputed interest
(87)
(160)
Total lease liabilities
$
932
720
*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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
122
At December 31, 2018, future minimum payments
 
due under finance (capital) leases pursuant
 
to
ASC Topic 840 were:
Millions
of Dollars
2019
$
118
2020
116
2021
100
2022
98
2023
87
Remaining years
453
Total
972
Less: portion representing imputed interest
(195)
Capital lease obligations
$
777
 
At December 31, 2018, future undiscounted minimum
 
rental payments due under noncancelable operating
leases pursuant to ASC Topic 840 were:
Millions
of Dollars
2019
$
248
2020
425
2021
136
2022
319
2023
54
Remaining years
212
Total
1,394
Less: income from subleases
(7)
Net minimum operating lease payments
$
1,387
 
For the years ended December 31, operating
 
lease rental expense pursuant to ASC Topic 840 was:
Millions of Dollars
2018
2017
Total rentals
$
253
264
Less: sublease rentals
(16)
(20)
$
237
244
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
123
Note 18—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
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Change in Benefit Obligation
Benefit obligation at January 1
$
2,136
3,438
3,236
3,845
218
265
Service cost
79
69
83
81
1
1
Interest cost
79
97
99
107
8
8
Plan participant contributions
-
2
-
2
20
22
Plan amendments
-
-
-
7
-
-
Actuarial (gain) loss
278
387
(44)
(259)
27
(10)
Benefits paid
(253)
(147)
(507)
(143)
(59)
(67)
Curtailment
-
(69)
(4)
(3)
-
-
Settlement
-
-
(730)
-
-
-
Recognition of termination benefits
-
1
3
-
-
-
Foreign currency exchange rate change
-
102
-
(199)
1
(1)
Benefit obligation at December 31*
$
2,319
3,880
2,136
3,438
216
218
*Accumulated benefit obligation portion of above at
 
December 31:
$
2,161
3,594
1,969
3,066
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
$
1,336
3,358
2,541
3,647
-
-
Actual return on plan assets
273
529
(112)
(106)
-
-
Company contributions
235
464
144
156
39
45
Plan participant contributions
-
2
-
2
20
22
Benefits paid
(253)
(147)
(507)
(143)
(59)
(67)
Settlement
-
-
(730)
-
-
-
Foreign currency exchange rate change
-
100
-
(198)
-
-
Fair value of plan assets at December 31
$
1,591
4,306
1,336
3,358
-
-
Funded Status
$
(728)
426
(800)
(80)
(216)
(218)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
124
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Noncurrent assets
$
-
765
-
232
-
-
Current liabilities
(21)
(6)
(59)
(4)
(42)
(44)
Noncurrent liabilities
(707)
(333)
(741)
(308)
(174)
(174)
Total recognized
$
(728)
426
(800)
(80)
(216)
(218)
Weighted-Average Assumptions Used to
Determine Benefit Obligations at
December 31
Discount rate
3.25
%
2.35
4.25
3.05
3.10
4.05
Rate of compensation increase
4.00
3.35
4.00
3.65
-
Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost for
Years
 
Ended December 31
Discount rate
3.95
%
2.90
3.80
2.90
4.05
3.30
Expected return on plan assets
5.80
4.10
5.80
4.30
-
Rate of compensation increase
4.00
3.65
4.00
3.75
-
 
 
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.
 
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
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
$
479
227
516
310
8
(21)
Unrecognized prior service cost (credit)
-
(2)
-
(4)
(183)
(216)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
125
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Sources of Change in Other
Comprehensive Income (Loss)
Net gain (loss) arising during the period
$
(79)
51
(177)
17
(27)
10
Amortization of actuarial (gain) loss included
in income (loss)*
116
32
249
31
(2)
(1)
Net change during the period
$
37
83
72
48
(29)
9
Prior service credit (cost) arising during the
period
$
-
-
-
(7)
-
-
Amortization of prior service cost (credit)
included in income (loss)
-
(2)
-
(5)
(33)
(35)
Net change during the period
$
-
(2)
-
(12)
(33)
(35)
*Includes settlement losses recognized in 2019 and 2018.
 
 
Included in accumulated other comprehensive
 
loss at December 31, 2019, were the following
 
before-tax
amounts that are expected to be amortized into
 
net periodic benefit cost during 2020:
Millions of Dollars
Pension
Other
Benefits
Benefits
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
$
50
23
1
Unrecognized prior service credit
-
(2)
(31)
 
 
For our tax-qualified pension plans with projected
 
benefit obligations in excess of plan
 
assets, the projected
benefit obligation, the accumulated benefit obligation,
 
and the fair value of plan assets were $
2,073
 
million,
$
1,919
 
million, and $
1,635
 
million, respectively, at December 31, 2019, and $
1,871
 
million, $
1,737
 
million,
and $
1,373
 
million, respectively, at December 31, 2018.
 
For our unfunded nonqualified key employee supplemental
 
pension plans, the projected benefit obligation and
the accumulated benefit obligation were $
601
 
million and $
542
 
million, respectively, at December 31, 2019,
and were $
586
 
million and $
504
 
million, respectively, at December 31, 2018.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
126
The components of net periodic benefit cost of
 
all defined benefit plans are presented in
 
the following table:
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2017
2019
2018
2017
U.S.
Int’l.
U.S.
Int’l.
U.S.
Int’l.
Components of Net
Periodic Benefit Cost
Service cost
$
79
69
83
81
89
77
1
1
2
Interest cost
79
97
99
107
118
103
8
8
9
Expected return on plan
assets
(74)
(138)
(114)
(155)
(132)
(158)
-
-
-
Amortization of prior
service cost (credit)
-
(2)
-
(5)
4
(6)
(33)
(35)
(36)
Recognized net actuarial
loss (gain)
54
32
53
31
69
50
(2)
(1)
(3)
Settlements
62
-
196
-
131
-
-
-
-
Net periodic benefit cost
$
200
58
317
59
279
66
(26)
(27)
(28)
 
 
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.
 
In 2018, we purchased a group annuity contract
 
from Prudential and transferred $
730
 
million of future benefit
obligations from the U.S. qualified pension plan to
 
Prudential.
 
The purchase of the group annuity contract
 
was
funded directly by plan assets of the U.S. qualified
 
pension plan.
 
Effective January 1, 2019, the Cash Balance
Account (Title II) of the ConocoPhillips Retirement Plan,
 
a U.S. qualified pension plan, was closed to new
entrants.
 
New employees and rehires on or after January
 
1, 2019, and employees that elected to opt out of
Title II will no longer receive pay credits to their Cash Balance
 
Account and instead will be eligible for a
Company Retirement Contribution (CRC) as
 
described in the Defined Contribution Plans section.
 
We recognized pension settlement losses of $
62
 
million in 2019, $
196
 
million in 2018, and $
131
 
million in
2017 as lump-sum benefit payments from certain
 
U.S. pension plans exceeded the sum of service
 
and interest
costs for those plans and led to recognition of settlement
 
losses.
 
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
2020 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 2020
 
127
that increases to
5
 
percent by
2028
.
 
A one-percentage-point change in the assumed
 
health care cost trend rate
would be immaterial to ConocoPhillips.
 
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
37
 
percent equity
securities,
56
 
percent debt securities,
6
 
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, 2019 and 2018.
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
128
 
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, 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.
 
At December 31, 2018, the participating interest
 
in the
annuity contract was valued at $
84
 
million and consisted of $
228
 
million in debt securities, less
 
$
144
million for the accumulated benefit obligation
 
covered by the contract.
 
The net change from 2018 to
2019 is due to an increase in the fair value of the
 
underlying investments of $
7
 
million offset by a
decrease in the present value of the contract obligation
 
of $
4
 
million.
 
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.
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
129
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
2018
Equity securities
U.S.
$
74
-
20
94
371
-
-
371
International
80
-
-
80
241
-
-
241
Mutual funds
76
-
-
76
213
181
-
394
Debt securities
Government
-
-
-
-
889
-
-
889
Corporate
-
2
-
2
-
-
-
-
Mutual funds
-
-
-
-
363
-
-
363
Cash and cash equivalents
-
-
-
-
71
-
-
71
Time deposits
-
-
-
-
6
-
-
6
Derivatives
-
-
-
-
(17)
-
-
(17)
Real estate
-
-
-
-
-
-
124
124
Total in fair value hierarchy
$
230
2
20
252
2,137
181
124
2,442
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
-
-
-
364
-
-
-
153
Debt securities
Common/collective trusts
-
-
-
548
-
-
-
641
Cash and cash equivalents
-
-
-
5
-
-
-
-
Real estate
-
-
-
80
-
-
-
109
Total**
$
230
2
20
1,249
2,137
181
124
3,345
 
*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 $
84
 
million and net receivables related to security
 
 
transactions of $
16
 
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 2020, we expect to contribute approximately $
350
million to our domestic qualified and nonqualified
 
pension and postretirement benefit plans and $
90
 
million to
our international qualified and nonqualified
 
pension and postretirement benefit plans.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
130
The following benefit payments, which are exclusive
 
of amounts to be paid from the insurance annuity
 
contract
and which reflect expected future service, as appropriate,
 
are expected to be paid:
Millions of Dollars
Pension
Other
Benefits
Benefits
U.S.
Int’l.
2020
$
447
150
32
2021
270
156
29
2022
250
158
27
2023
217
163
24
2024
220
170
22
2025–2029
822
927
64
 
 
Severance Accrual
The following table summarizes our severance accrual
 
activity for the year ended December 31, 2019:
 
Millions of Dollars
Balance at December 31, 2018
$
48
Accruals
(1)
Benefit payments
(24)
Balance at December 31, 2019
$
23
 
 
Of the remaining balance at December 31, 2019,
 
$
5
 
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 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 $
82
 
million in 2019, $
82
 
million in 2018, and
$
77
 
million in 2017.
 
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 $
30
 
million in 2019, $
31
 
million in 2018, and $
35
 
million in 2017.
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
131
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).
 
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 income (loss) and the
associated tax benefit for the years ended
 
December 31 were as follows:
Millions of Dollars
2019
2018
2017
Compensation cost
$
274
265
227
Tax benefit
71
64
76
 
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.
 
The fair market values of the options granted in
 
2017 were measured on the date of grant
 
using the
Black-Scholes-Merton option-pricing model.
 
The weighted-average assumptions used were as follows:
2017
Assumptions used
Risk-free interest rate
2.24
%
Dividend yield
4.00
%
Volatility
 
factor
28.12
%
Expected life (years)
6.39
 
 
There were no ranges in the assumptions used to
 
determine the fair market values of our options
 
granted in
2017.
 
We believe our historical volatility for periods prior to the 2012 separation of our
 
Downstream businesses is no
longer relevant in estimating expected volatility.
 
For 2017,
 
expected volatility was based on the weighted-
average blend of the company’s historical stock price volatility from
 
May 1, 2012 (the date of separation of our
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
132
Downstream businesses) through the stock option
 
grant date and the average historical
 
stock price volatility of
a group of peer companies for the expected term
 
of the options.
 
The following summarizes our stock option activity
 
for the year ended December 31, 2019:
Millions of Dollars
Weighted-Average
Aggregate
Options
Exercise Price
Intrinsic Value
Outstanding at December 31, 2018
19,379,677
$
52.88
$
214
Exercised
(1,339,480)
36.28
39
Forfeited
-
Expired or cancelled
-
Outstanding at December 31, 2019
18,040,197
$
54.11
$
206
Vested at December 31, 2019
17,922,026
$
54.14
$
205
Exercisable at December 31, 2019
17,172,815
$
54.33
$
194
 
 
The weighted-average remaining contractual term
 
of outstanding options, vested options and exercisable
options at December 31, 2019, was
4.43
 
years,
4.41
 
years and
4.29
 
years, respectively.
 
The weighted-average
grant date fair value of stock option awards granted
 
during 2017 was $
9.18
.
 
The aggregate intrinsic value of
options exercised was $
94
 
million in 2018 and $
4
 
million in 2017.
 
 
During 2019, we received $
49
 
million in cash and realized a tax benefit
 
of $
13
 
million from the exercise of
options.
 
At December 31, 2019, the remaining unrecognized
 
compensation expense from unvested options
was
zero
.
 
Stock Unit Program—
Generally, restricted stock units are granted annually under the provisions of the Plan
and vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock
units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual
installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc
to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest
vary by award
.
 
Stock-Settled
Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per
unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not issued as common stock until the earlier of separation from the company or the end of the regularly
scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a quarterly
cash payment of a dividend equivalent that is charged to retained earnings. The grant date fair market value of
these restricted stock units is deemed equal to the average ConocoPhillips stock price on the grant date. The
grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal
to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will
not be received
.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
133
The following summarizes our stock-settled stock
 
unit activity for the year ended December
 
31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
7,546,973
$
43.41
Granted
2,045,503
67.77
Forfeited
(99,748)
62.93
Issued
(3,269,682)
34.32
$
225
Outstanding at December 31, 2019
6,223,046
$
55.99
Not Vested at December 31, 2019
4,185,141
56.17
 
 
At December 31, 2019,
 
the remaining unrecognized compensation
 
cost from the unvested stock-settled units
was $
93
 
million, which will be recognized over
 
a weighted-average period of
1.71
 
years, the longest period
being
2.73
 
years.
 
The weighted-average grant date fair value
 
of stock unit awards granted during 2018 and
2017 was $
52.45
 
and $
48.77
, respectively.
 
The total fair value of stock units issued during
 
2018 and 2017 was
$
154
 
million and $
159
 
million, respectively.
 
Cash-Settled
Beginning in 2018, cash-settled executive restricted stock units 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.
 
The following summarizes our cash-settled stock
 
unit activity for the year ended December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
376,608
$
62.21
Granted
319,552
68.20
Forfeited
(6,914)
61.35
Issued
(92,255)
61.61
$
6
Outstanding at December 31, 2019
596,991
$
64.54
Not Vested at December 31, 2019
153,457
64.54
 
At December 31, 2019,
 
the remaining unrecognized compensation
 
cost from the unvested cash-settled units
was $
5
 
million, which will be recognized over a
 
weighted-average period of
1.70
 
years, the longest period
being
2.12
 
years.
 
The weighted-average grant date fair value
 
of stock unit awards granted during 2018
 
was
$
53.68
.
 
The total fair value of stock units issued during
 
2018 was $
1
 
million.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
134
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.
 
The following summarizes our stock-settled Performance
 
Share Program activity for the year ended
December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
2,335,542
$
50.45
Granted
77,841
68.90
Forfeited
-
Issued
(388,559)
53.66
$
25
Outstanding at December 31, 2019
2,024,824
$
50.55
Not Vested at December 31, 2019
15,616
$
47.80
 
 
At December 31, 2019,
 
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 2018 and 2017 was $
53.28
 
and $
49.76
, respectively.
 
The total fair value of stock-settled PSUs issued
during 2018 and 2017 was $
29
 
million and $
57
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
135
dividend equivalent that is charged to compensation expense.
 
Beginning in 2013, PSUs authorized for future grants
 
will vest upon settlement following the conclusion
 
of the
three-year performance period.
 
We recognize compensation expense over the period beginning on the date of
authorization and ending at the conclusion of
 
the performance period.
 
These PSUs will be settled in cash equal
to the fair market value of a share of ConocoPhillips
 
common stock per unit on the settlement date
 
and are
classified as liabilities on the balance sheet.
 
For performance periods beginning before
 
2018, during the
performance period, recipients of the PSUs do
 
not receive a quarterly cash payment of a dividend
 
equivalent,
but after the performance period ends, until
 
settlement in cash occurs, recipients of the PSUs
 
receive a
quarterly cash payment of a dividend equivalent
 
that is charged to compensation expense.
 
For the performance
period beginning in 2018, recipients of the PSUs
 
receive an accrued reinvested dividend equivalent
 
that is
charged to compensation expense.
 
The accrued reinvested dividend is paid at
 
the time of settlement, subject to
the terms and conditions of the award.
 
 
The following summarizes our cash-settled Performance
 
Share Program activity for the year ended
December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
1,131,007
$
62.21
Granted
1,958,043
68.90
Forfeited
-
Settled
(2,479,776)
69.10
$
171
Outstanding at December 31, 2019
609,274
$
64.54
Not Vested at December 31, 2019
38,487
$
64.54
 
 
At December 31, 2019,
 
the remaining unrecognized compensation
 
cost from unvested cash-settled
performance share awards was
zero
.
 
The weighted-average grant date fair value of
 
cash-settled PSUs granted
during 2018 and 2017 was $
53.28
 
and $
49.76
, respectively.
 
The total fair value of cash-settled performance
share awards settled during 2018 and 2017
 
was $
22
 
million and $
24
 
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 quarterly dividend
 
or
dividend equivalent.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
136
The following summarizes the aggregate activity
 
of these restricted shares and units for the
 
year ended
December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
1,107,315
$
46.57
Granted
64,063
63.58
Cancelled
(2,307)
23.73
Issued
(177,163)
49.23
$
11
Outstanding at December 31, 2019
991,908
$
47.24
 
 
At December 31, 2019, 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 2018 and 2017 was $
62.01
 
and $
48.87
, respectively.
 
The total fair value of awards issued
during 2018 and 2017 was $
17
 
million and $
4
 
million, respectively.
 
 
 
Note 19—Income Taxes
Income taxes charged to net income (loss) were:
Millions of Dollars
2019
2018
2017
Income Taxes
Federal
Current
$
18
4
79
Deferred
(113)
545
(3,046)
Foreign
Current
2,545
3,273
1,729
Deferred
(323)
(166)
(510)
State and local
Current
148
108
51
Deferred
(8)
(96)
(125)
$
2,267
3,668
(1,822)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
137
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
2019
2018
Deferred Tax Liabilities
PP&E and intangibles
$
8,660
8,004
Inventory
35
60
Deferred state income tax
-
61
Other
234
156
Total deferred tax liabilities
8,929
8,281
Deferred Tax Assets
Benefit plan accruals
542
641
Asset retirement obligations and accrued environmental
 
costs
2,339
2,891
Investments in joint ventures
1,722
104
Other financial accruals and deferrals
777
330
Loss and credit carryforwards
8,968
2,378
Other
345
398
Total deferred tax assets
14,693
6,742
Less: valuation allowance
(10,214)
(3,040)
Net deferred tax assets
4,479
3,702
Net deferred tax liabilities
$
4,450
4,579
 
 
At December 31, 2019, noncurrent assets and liabilities
 
included deferred taxes of $
184
 
million and
$
4,634
 
million, respectively.
 
At December 31, 2018, noncurrent assets and liabilities
 
included deferred taxes
of $
442
 
million and $
5,021
 
million, respectively.
 
 
 
At December 31, 2019, the components of
 
our loss and credit carryforwards before and
 
after consideration of
the applicable valuation allowances were:
Millions of Dollars
Net Deferred
Expiration of
Gross Deferred
Tax Asset After
Net Deferred
Tax Asset
Valuation Allowance
Tax Asset
U.S. foreign tax credits
$
7,696
14
2028
U.S. general business credits
250
250
2036-2038
U.S. capital loss
202
32
2024
State net operating losses and tax credits
370
50
Various
Foreign net operating losses and tax credits
450
413
Post 2025
$
8,968
759
 
 
Valuation
 
allowances have been established to reduce
 
deferred tax assets to an amount that will,
 
more likely
than not, be realized.
 
During 2019, valuation allowances increased a total
 
of $
7,174
 
million.
 
The increase
primarily relates to deferred tax assets recognized
 
during 2019 as a result of the finalization of rules
 
related to
the U.S. Tax Cuts and Jobs Act (Tax Legislation including ongoing issuance of tax regulations related to such
legislation), as further discussed below.
 
Based on our historical taxable income, expectations
 
for the future,
and available tax-planning strategies, management
 
expects deferred tax assets, net of valuation
 
allowance, will
primarily be realized as offsets to reversing deferred tax
 
liabilities.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
138
 
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, 2019, unremitted income
 
considered to be permanently reinvested in
 
certain foreign
subsidiaries and foreign corporate joint ventures
 
totaled approximately $
4,196
 
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
 
$
210
 
million.
 
The following table shows a reconciliation
 
of the beginning and ending unrecognized tax
 
benefits for 2019,
2018 and 2017:
Millions of Dollars
2019
2018
2017
Balance at January 1
$
1,081
882
381
Additions based on tax positions related to the current
 
year
9
268
612
Additions for tax positions of prior years
120
43
109
Reductions for tax positions of prior years
(22)
(73)
(129)
Settlements
(9)
(35)
(5)
Lapse of statute
(2)
(4)
(86)
Balance at December 31
$
1,177
1,081
882
 
 
Included in the balance of unrecognized tax benefits
 
for 2019, 2018 and 2017 were $
1,100
 
million,
$
1,081
 
million and $
882
 
million, respectively, which, if recognized, would impact our effective tax rate.
 
The
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.
 
The balance of unrecognized tax benefits
 
increased in 2017
mainly due to the recognition of a U.S. worthless securities
 
deduction that we do not believe will generate a
cash tax benefit.
 
See Note 13—Contingencies and Commitments,
 
for more information on the PDVSA
settlement.
 
 
At December 31, 2019, 2018 and 2017, accrued liabilities
 
for interest and penalties totaled $
42
 
million,
$
45
 
million and $
54
 
million, respectively, net of accrued income taxes.
 
Interest and penalties resulted in a
benefit to earnings of $
3
 
million in 2019, a benefit to earnings
 
of $
4
 
million in 2018, and
no
 
impact to earnings
in 2017.
 
 
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 (2018).
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
139
The amounts of U.S. and foreign income (loss)
 
before income taxes, with a reconciliation of tax
 
at the federal
statutory rate with the provision for income taxes,
 
were:
Millions of Dollars
Percent of Pre-Tax Income (Loss)
2019
2018
2017
2019
2018
2017
Income (loss) before income taxes
United States
$
4,704
2,867
(5,250)
49.4
%
28.7
200.8
Foreign
4,820
7,106
2,635
50.6
71.3
(100.8)
$
9,524
9,973
(2,615)
100.0
%
100.0
100.0
Federal statutory income tax
$
2,000
2,095
(915)
21.0
%
21.0
35.0
Non-U.S. effective tax rates
1,399
1,766
625
14.7
17.7
(23.9)
Tax Legislation
-
(10)
(852)
-
(0.1)
32.6
Canada disposition
-
-
(1,277)
-
-
48.8
U.K. disposition
(732)
(150)
-
(7.7)
(1.5)
-
Recovery of outside basis
(77)
(21)
(962)
(0.8)
(0.2)
36.8
Adjustment to tax reserves
9
(4)
881
0.1
-
(33.7)
Adjustment to valuation allowance
(225)
(26)
-
(2.4)
(0.3)
-
APLNG impairment
-
-
834
-
-
(31.9)
State income tax
123
135
(84)
1.3
1.4
3.2
Malaysia Deepwater Incentive
(164)
-
-
(1.7)
-
-
Enhanced oil recovery credit
(27)
(99)
(68)
(0.3)
(1.0)
2.6
Other
(39)
(18)
(4)
(0.4)
(0.2)
0.2
$
2,267
3,668
(1,822)
23.8
%
36.8
69.7
 
 
Our effective tax rate for 2019 was favorably impacted
 
by the sale of two of our U.K. subsidiaries.
 
The
disposition generated a before-tax gain of more than
 
$
1.7
 
billion with an associated tax benefit of $
335
million. The disposition generated a U.S. capital
 
loss of approximately $
2.1
 
billion which has generated a U.S.
tax benefit of approximately $
285
 
million. The remaining U.S. capital loss
 
has been recorded as a deferred tax
asset fully offset with a valuation allowance.
 
See Note 5—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 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 5—Asset Acquisitions and
Dispositions,
 
for additional information on the disposition.
 
Tax Legislation was enacted in the U.S. on December 22, 2017, reducing the
 
U.S. federal corporate income tax
rate to 21 percent from 35 percent, requiring companies
 
to pay a one-time transition tax on earnings of certain
foreign subsidiaries that were previously tax deferred
 
and creating new taxes on certain foreign-sourced
earnings.
 
 
 
 
 
 
 
 
140
SAB 118 measurement period
 
We applied the guidance in Staff Accounting Bulletin No. 118 when accounting for the enactment-date effects
of Tax Legislation in 2017 and throughout 2018.
 
At December 31, 2017, we had not completed
 
our
accounting for all the enactment-date income
 
tax effects of Tax Legislation under ASC 740, Income Taxes, for
the remeasurement of deferred tax assets and liabilities
 
and the one-time transition tax.
 
As of December 31,
2018, we had completed our accounting for all the
 
enactment-date income tax effects of Tax Legislation.
 
As
further discussed below, during 2018, we recognized adjustments of $
10
 
million to the provisional amounts
recorded at December 31, 2017, and included these
 
adjustments as a component
 
of income tax provision.
 
 
Provisional Amounts—Foreign tax effects
The one-time transition tax is based on our total
 
post-1986 earnings, the tax on which we previously
 
deferred
from U.S. income taxes under U.S. law.
 
We estimated at December 31, 2017, that we would not incur a one-
time transition tax.
 
 
Upon further analyses of Tax Legislation and Notices and regulations issued and proposed
by the U.S. Department of the Treasury and the Internal Revenue
 
Service, we finalized our calculations of the
transition tax liability during 2018.
 
Based upon this analysis, we did not incur a
 
one-time transition tax.
 
 
As a result of the Tax Legislation, we removed the indefinite reinvestment
 
assertion on one of our foreign
subsidiaries and recorded a tax expense of $
56
 
million in the fourth quarter of 2017.
 
Deferred tax assets and liabilities
As of December 31, 2017, we remeasured certain deferred
 
tax assets and liabilities based on the rates at
 
which
they were expected to reverse in the future (which
 
was generally 21 percent), by recording a provisional
amount of $
908
 
million.
 
Upon further analysis of certain aspects of
 
Tax Legislation and refinement of our
calculations during the 12 months ended December
 
31, 2018, we adjusted our provisional amount by
 
$
10
million, which is included as a component of income
 
tax expense.
 
 
Global intangible low-taxed income (GILTI)
 
We have elected to account for GILTI
 
in the year the tax is incurred.
 
For 2019 and 2018,
 
the current-year U.S.
income tax impact related to GILTI activities is immaterial.
 
 
Our effective tax rate in 2017 was favorably impacted
 
by a tax benefit of $
1,277
 
million related to the Canada
disposition.
 
This tax benefit was primarily associated with
 
a deferred tax recovery related to the Canadian
capital gains exclusion component of the 2017
 
Canada disposition and the recognition
 
of previously
unrealizable Canadian capital asset tax basis.
 
The Canada disposition, along with the
 
associated restructuring
of our Canadian operations, may generate an additional
 
tax benefit of $
822
 
million.
 
However, since we
believe it is not likely we will receive a corresponding
 
cash tax savings, this $
822
 
million benefit has been
offset by a full tax reserve.
 
See Note 5—Asset Acquisitions and Dispositions
 
for additional information on our
Canada disposition.
 
 
The impairment of our APLNG investment in the
 
second quarter of 2017 did not generate
 
a tax benefit.
 
See
the “APLNG” section of Note 6—Investments,
 
Loans and Long-Term Receivables, for information on the
impairment of our APLNG investment.
 
 
Certain operating losses in jurisdictions outside
 
of the U.S.
 
only yield a tax benefit in the U.S. as a worthless
security deduction.
 
For 2019, 2018 and 2017, before consideration
 
of unrecorded tax benefits discussed above,
the amount of the tax benefit was $
9
 
million, $
36
 
million and $
962
 
million, respectively.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
141
Note 20—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, 2016
$
(547)
-
(5,646)
(6,193)
Other comprehensive income (loss)
147
(58)
586
675
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)
 
*We adopted ASU No. 2016-01, "Recognition and Measurement of Financial Assets and Liabilities," beginning
 
January 1, 2018.
 
**See Note 2
Changes in Accounting Principles for additional information.
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 5—Asset Acquisitions and Dispositions.
There were no items within accumulated other comprehensive
 
loss related to noncontrolling interests.
The following table summarizes reclassifications
 
out of accumulated other comprehensive loss during
 
the years
ended December 31:
Millions of Dollars
2019
2018
Defined Benefit Plans
$
88
189
Above amounts are included in the computation of net periodic benefit cost
 
and
 
are presented net of tax expense of:
$
23
50
See Note 18—Employee Benefit Plans, for additional information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
142
Note 21—Cash Flow Information
Millions of Dollars
2019
2018
2017
Noncash Investing Activities
Increase (decrease) in PP&E related to an increase
 
(decrease) in asset
retirement obligations
$
205
395
(37)
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
$
810
772
1,163
Income taxes
2,905
2,976
1,168
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(4,902)
(1,953)
(6,617)
Short-term investments sold
2,138
3,573
4,827
Investments and long-term receivables purchased
(146)
-
-
$
(2,910)
1,620
(1,790)
*See Note 5—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.
 
We collected $
262
 
million and $
75
 
million
from Ecuador in 2018 and 2017, respectively, as installment payments related
 
to an agreement reached with
Ecuador in 2017.
 
For more information on these settlements,
 
see Note 13—Contingencies and Commitments.
 
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 and $
600
 
million in 2018 and 2017, respectively.
 
In 2017, we recognized a $
180
 
million adverse cash impact from the settlement
 
of cross-currency swap
transactions.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
143
Note 22—Other Financial Information
Millions of Dollars
2019
2018
2017
Interest and Debt Expense
Incurred
Debt
$
799
838
1,114
Other
36
67
103
835
905
1,217
Capitalized
(57)
(170)
(119)
Expensed
$
778
735
1,098
Other Income
Interest income
$
166
97
112
Unrealized gains (losses) on Cenovus Energy common shares*
649
(437)
-
Other, net
543
513
417
$
1,358
173
529
*See Note 7—Investment in Cenovus Energy, for additional information.
Research and Development Expenditures
—expensed
$
82
78
100
Shipping and Handling Costs
$
1,008
1,075
1,050
Foreign Currency Transaction (Gains) Losses
—after-tax
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
5
(11)
3
Europe and North Africa
-
(26)
7
Asia Pacific and Middle East
31
3
23
Other International
1
-
1
Corporate and Other
21
21
(3)
$
58
(13)
31
 
 
Millions of Dollars
2019
2018
Properties, Plants and Equipment
Proved properties
$
88,284
*
100,657
Unproved properties
3,980
*
4,662
Other
5,482
5,278
Gross properties, plants and equipment
97,746
110,597
Less: Accumulated depreciation, depletion and amortization
(55,477)
*
(64,899)
Net properties, plants and equipment
$
42,269
45,698
*Excludes assets classified as held for sale at December 31,
 
2019.
 
See Note 5
Asset Acquisitions and Dispositions, for additional information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
144
Note 23—Related Party Transactions
Our related parties primarily include equity method
 
investments and certain trusts for the benefit
 
of employees.
Significant transactions with our equity affiliates
 
were:
 
Millions of Dollars
2019
2018
2017
Operating revenues and other income
$
89
98
107
Purchases
38
98
99
Operating expenses and selling, general and administrative
 
expenses
65
60
59
Net interest (income) expense*
(13)
(14)
(13)
*We paid interest to, or received interest from,
 
various affiliates.
 
See Note 6—Investments, Loans and Long-Term Receivables, for additional
 
information on loans to affiliated companies.
 
 
The table above includes transactions with the
 
FCCL Partnership through the date of the
 
sale.
 
See Note 6—
Investments, Loans and Long-Term Receivables, for additional information.
 
 
Note 24—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
2019
2018
2017
Revenue from contracts with customers
$
26,106
28,098
20,525
Revenue from contracts outside the scope of ASC
 
Topic 606
Physical contracts meeting the definition of a derivative
6,558
8,218
8,669
Financial derivative contracts
(97)
101
(88)
Consolidated sales and other operating revenues
$
32,567
36,417
29,106
 
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 25—Segment Disclosures and Related
Information:
 
 
Millions of Dollars
2019
2018
2017
Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
$
4,989
6,358
6,302
Canada
691
629
864
Europe and North Africa
878
1,231
1,503
Physical contracts meeting the definition of a derivative
$
6,558
8,218
8,669
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
145
Millions of Dollars
2019
2018
2017
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
804
1,112
588
Natural gas
5,313
6,734
7,811
Other
441
372
270
Physical contracts meeting the definition of a derivative
$
6,558
8,218
8,669
 
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, 2019, the “Accounts and
 
notes receivable” line on our consolidated
 
balance sheet included
trade receivables of $
2,372
 
million compared with $
2,889
 
million at December 31, 2018, 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, 2018
$
206
Contractual payments received
73
Revenue recognized
(199)
At December 31, 2019
$
80
 
We expect to recognize the contract liabilities as of December 31, 2019, as revenue during 2021 and 2022.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
146
Note 25—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 and
 
North Africa, Asia Pacific and Middle East,
 
and Other
International.
 
Corporate and Other represents 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.
 
 
Analysis of Results by Operating Segment
Millions of Dollars
2019
2018
2017
Sales and Other Operating Revenues
Alaska
$
5,483
5,740
4,224
Lower 48
15,514
17,029
12,968
Intersegment eliminations
(46)
(40)
(4)
Lower 48
15,468
16,989
12,964
Canada
2,910
3,184
3,178
Intersegment eliminations
(1,141)
(1,160)
(559)
Canada
1,769
2,024
2,619
Europe and North Africa
5,101
6,635
5,181
Asia Pacific and Middle East
4,525
4,861
4,014
Other International
-
-
-
Corporate and Other
221
168
104
Consolidated sales and other operating revenues
$
32,567
36,417
29,106
 
Depreciation, Depletion, Amortization and Impairments
Alaska
$
805
760
1,026
Lower 48
3,224
2,370
6,693
Canada
232
324
461
Europe and North Africa
887
1,041
1,313
Asia Pacific and Middle East
1,285
1,382
3,819
Other International
-
-
-
Corporate and Other
62
106
134
Consolidated depreciation, depletion, amortization
 
and impairments
$
6,495
5,983
13,446
The market for our products is large and diverse, therefore,
 
our sales and other operating revenues are not
dependent upon any single customer.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
147
Millions of Dollars
2019
2018
2017
Equity in Earnings of Affiliates
Alaska
$
7
6
7
Lower 48
(159)
1
5
Canada
-
-
197
Europe and North Africa
16
16
10
Asia Pacific and Middle East
915
1,051
553
Other International
-
-
-
Corporate and Other
-
-
-
Consolidated equity in earnings of affiliates
$
779
1,074
772
 
Income Taxes
Alaska
$
472
376
(689)
Lower 48
137
474
(2,453)
Canada
(43)
(96)
(616)
Europe and North Africa
1,435
2,265
1,165
Asia Pacific and Middle East
491
722
351
Other International
8
30
21
Corporate and Other
(233)
(103)
399
Consolidated income taxes
$
2,267
3,668
(1,822)
 
Net Income (Loss) Attributable to ConocoPhillips
Alaska
$
1,520
1,814
1,466
Lower 48
436
1,747
(2,371)
Canada
279
63
2,564
Europe and North Africa
2,724
1,866
553
Asia Pacific and Middle East
1,929
2,070
(1,098)
Other International
263
364
167
Corporate and Other
38
(1,667)
(2,136)
Consolidated net income (loss) attributable
 
to ConocoPhillips
$
7,189
6,257
(855)
 
Investments in and Advances to Affiliates
Alaska
$
83
86
56
Lower 48
35
378
402
Canada
-
-
-
Europe and North Africa
54
55
55
Asia Pacific and Middle East
8,281
8,821
9,077
Other International
-
-
-
Corporate and Other
-
-
-
Consolidated investments in and advances to affiliates
$
8,453
9,340
9,590
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
148
Millions of Dollars
2019
2018
2017
Total Assets
Alaska
$
15,453
14,648
12,108
Lower 48
14,425
14,888
14,632
Canada
6,350
5,748
6,214
Europe and North Africa
8,121
9,883
11,870
Asia Pacific and Middle East
14,716
16,151
16,985
Other International
285
89
97
Corporate and Other
11,164
8,573
11,456
Consolidated total assets
$
70,514
69,980
73,362
 
Capital Expenditures and Investments
Alaska
$
1,513
1,298
815
Lower 48
3,394
3,184
2,136
Canada
368
477
202
Europe and North Africa
708
877
872
Asia Pacific and Middle East
584
718
482
Other International
8
6
21
Corporate and Other
61
190
63
Consolidated capital expenditures and investments
$
6,636
6,750
4,591
 
Interest Income and Expense
Interest income
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
-
-
-
Europe and North Africa
2
2
2
Asia Pacific and Middle East
15
15
9
Other International
-
-
-
Corporate and Other
149
80
101
Interest and debt expense
Corporate and Other
$
778
735
1,098
 
Sales and Other Operating Revenues by
 
Product
Crude oil
$
18,482
19,571
13,260
Natural gas
8,715
10,720
10,773
Natural gas liquids
814
1,114
1,102
Other*
4,556
5,012
3,971
Consolidated sales and other operating revenues
 
by product
$
32,567
36,417
29,106
*Includes LNG and bitumen.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
149
Geographic Information
Millions of Dollars
Sales and Other Operating Revenues
(1)
Long-Lived Assets
(2)
2019
2018
2017
2019
2018
2017
United States
(3)
$
21,159
22,740
17,204
26,566
26,838
23,623
Australia and Timor-Leste
(4)
1,647
1,798
1,448
7,228
9,301
9,657
Canada
1,769
2,024
2,619
5,769
5,333
5,613
China
772
836
712
1,447
1,380
1,275
Indonesia
875
886
757
605
669
758
Libya
1,103
1,142
586
668
679
699
Malaysia
1,230
1,346
1,103
1,871
2,327
2,736
Norway
2,349
2,886
2,348
5,258
5,582
6,154
United Kingdom
1,649
2,606
2,248
2
1,583
3,335
Other foreign countries
14
153
81
1,308
1,346
1,423
Worldwide consolidated
$
32,567
36,417
29,106
50,722
55,038
55,273
(1) Sales and other operating revenues are attributable
 
to countries based on the location of the selling operation.
(2) Defined as net PP&E plus equity investments
 
and advances to affiliated companies.
(3) Long-lived assets do not include $
426
 
million of net PP&E associated with assets held
 
for sale as of December 31,
2019.
 
See Note 5—Acquisitions and Dispositions, for additional
 
information.
(4) Long-lived assets do not include $
1,236
 
million of net PP&E associated with assets
 
held for sale as of December
31, 2019.
 
See Note 5—Acquisitions and Dispositions, for additional
 
information.
 
 
 
Note 26—New Accounting Standards
 
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on
 
Financial Instruments”
(ASU No. 2016-13), which sets forth the current
 
expected credit loss model, a new forward-looking
impairment model for certain financial instruments
 
based on expected losses rather than incurred losses.
 
The
ASU is effective for interim and annual periods beginning
 
after December 15, 2019.
 
Entities are required to
adopt ASU No. 2016-13 using a modified retrospective
 
approach, subject to certain limited exceptions.
 
The
impact
 
of adopting this ASU is not expected to be material
 
to our financial statements.
 
 
 
 
150
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, and Africa. Period end proved
 
reserves, capitalized costs, wells and acreage
 
include held-
for-sale assets at December 31, 2019. See Note 5—Asset
 
Acquisitions and Dispositions, in the Notes to
Consolidated Financial Statements, for additional
 
information on held-for-sale assets.
 
 
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, 2019, approximately
 
6 percent of our total
proved reserves were under PSCs, located in
 
our Asia Pacific/Middle East geographic
 
reporting area, and 6
percent of our total proved reserves were under
 
a variable-royalty regime, located in our Canada
 
geographic
reporting area.
 
Reserves Governance
 
The recording and reporting of proved reserves
 
are governed by criteria established by regulations
 
of the SEC
and FASB.
 
Proved reserves are those quantities of oil
 
and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable
 
certainty to be economically producible—from
 
a given date
forward, from known reservoirs, and under existing
 
economic conditions, operating methods, and government
regulations—prior to the time at which contracts
 
providing the right to operate expire, unless
 
evidence
indicates renewal is reasonably certain, regardless
 
of whether deterministic or probabilistic
 
methods are used
for the estimation.
 
The project to extract the hydrocarbons must
 
have commenced or the operator must be
reasonably certain it will commence the project
 
within a reasonable time.
 
 
Proved reserves are further classified as either
 
developed or undeveloped.
 
Proved developed reserves are
proved reserves that can be expected to be recovered
 
through existing wells with existing equipment
 
and
operating methods, or in which the cost of the required
 
equipment is relatively minor compared
 
with the cost
of a new well, and through installed extraction
 
equipment and infrastructure operational
 
at the time of the
reserves estimate if the extraction is by means not
 
involving a well.
 
Proved undeveloped reserves are proved
reserves expected to be recovered from new
 
wells on undrilled acreage, or from existing wells
 
where a
relatively major expenditure is required for
 
recompletion. Reserves on undrilled acreage
 
are limited to those
directly offsetting development spacing areas that
 
are reasonably certain of production when drilled,
 
unless
evidence provided by reliable technologies exists
 
that establishes reasonable certainty of economic
producibility at greater distances. As defined
 
by SEC regulations, reliable technologies
 
may be used in reserve
estimation when they have been demonstrated
 
in the field to provide reasonably certain results
 
with
consistency and repeatability in the formation
 
being evaluated or in an analogous formation.
 
The technologies
and data used in the estimation of our proved reserves
 
include, but are not limited to, performance-based
 
151
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 2019, our processes and controls used
 
to assess over 90 percent of proved reserves
 
as of December 31,
2019, 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, 2019, 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
152
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 2016
837
506
1,343
13
303
185
203
2,047
Revisions
113
65
178
1
38
32
-
249
Improved recovery
6
-
6
-
-
-
-
6
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
41
210
251
-
-
2
-
253
Production
(60)
(64)
(124)
(1)
(45)
(34)
(7)
(211)
Sales
-
(10)
(10)
(12)
-
-
-
(22)
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
Equity affiliates
End of 2016
-
 
-
-
-
-
 
88
-
 
88
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
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
Total
 
company
End of 2016
837
506
1,343
13
303
273
203
2,135
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
153
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 2016
747
256
1,003
13
184
106
203
1,509
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
Equity affiliates
End of 2016
-
-
-
-
-
88
-
88
End of 2017
-
-
-
-
-
83
-
83
End of 2018
-
-
-
-
-
78
-
78
End of 2019
-
-
-
-
-
73
-
73
Undeveloped
Consolidated operations
End of 2016
90
250
340
-
119
79
-
538
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
Equity affiliates
End of 2016
-
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
-
 
 
Notable changes in proved crude oil reserves
 
in the three years ended December 31, 2019,
 
included:
 
 
Revisions
: 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.
 
 
In 2017, revisions in Alaska, Lower 48, 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.
 
 
 
 
 
154
 
Extensions and discoveries
: 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.
 
In 2017, extensions and discoveries in Lower 48
 
were primarily due to continued drilling success
 
in the Permian
Unconventional, Eagle Ford and Bakken.
 
 
 
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.
 
In 2017,
Canada sales were due to the disposition of
 
a majority of our western Canada assets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
155
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 2016
107
278
385
48
19
5
457
Revisions
4
29
33
-
2
1
36
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
71
71
-
-
1
72
Production
(5)
(24)
(29)
(3)
(3)
(2)
(37)
Sales
-
(130)
(130)
(44)
-
-
(174)
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
Equity affiliates
End of 2016
-
 
-
-
-
-
 
47
47
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(2)
(2)
Sales
-
-
-
-
-
-
-
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
Total
 
company
End of 2016
107
278
385
48
19
52
504
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
Consolidated operations
End of 2016
107
209
316
47
15
5
383
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
Equity affiliates
End of 2016
-
-
-
-
-
47
47
End of 2017
-
-
-
-
-
45
45
End of 2018
-
-
-
-
-
42
42
End of 2019
-
-
-
-
-
39
39
Undeveloped
Consolidated operations
End of 2016
-
69
69
1
4
-
74
End of 2017
-
123
123
-
2
3
128
End of 2018
-
125
125
1
2
-
128
End of 2019
-
146
146
1
3
-
150
Equity affiliates
End of 2016
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
 
 
Notable changes in proved NGL reserves in the three
 
years ended December 31, 2019,
 
included:
 
 
Revisions
: 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.
 
 
In 2017, revisions in Lower 48 were primarily
 
due to higher prices.
 
 
Extensions and discoveries
: 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.
 
 
In 2017, extensions and discoveries in Lower 48
 
were primarily due to continued drilling success
 
in the Permian
Unconventional, Eagle Ford and Bakken.
 
 
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.
 
In 2017, Lower 48 sales were due to the
 
disposition of our interests in the
San Juan Basin and Panhandle assets, while Canada
 
sales were due to the disposition of a majority
 
of our western
Canada assets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
157
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 2016
2,102
4,714
6,816
1,037
1,238
1,526
227
10,844
Revisions
287
460
747
8
167
16
-
938
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
2
582
584
3
-
23
-
610
Production
(71)
(338)
(409)
(71)
(188)
(267)
(3)
(938)
Sales
-
(2,885)
(2,885)
(966)
-
-
-
(3,851)
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
Equity affiliates
End of 2016
-
-
-
-
-
4,381
-
4,381
Revisions
-
-
-
-
-
111
-
111
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
185
-
185
Production
-
-
-
-
-
(374)
-
(374)
Sales
-
-
-
-
-
-
-
-
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
Total
 
company
End of 2016
2,102
4,714
6,816
1,037
1,238
5,907
227
15,225
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
Consolidated operations
End of 2016
2,094
4,199
6,293
1,031
998
1,188
227
9,737
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
Equity affiliates
End of 2016
-
-
-
-
-
4,110
-
4,110
End of 2017
-
-
-
-
-
4,044
-
4,044
End of 2018
-
-
-
-
-
4,059
-
4,059
End of 2019
-
-
-
-
-
3,898
-
3,898
Undeveloped
Consolidated operations
End of 2016
8
515
523
6
240
338
-
1,107
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
Equity affiliates
End of 2016
-
-
-
-
-
271
-
271
End of 2017
-
-
-
-
-
259
-
259
End of 2018
-
-
-
-
-
505
-
505
End of 2019
-
-
-
-
-
523
-
523
 
 
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 3,141 Bcf,
 
3,131 Bcf, and 3,825 Bcf as of December 31,
2019, 2018 and 2017, 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, 2019, included:
 
 
Revisions
: 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.
 
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.
 
 
In 2017, revisions in Alaska, Lower 48 and
 
Europe were primarily due to higher prices.
 
 
 
 
159
 
 
Purchases
: In 2018, Alaska purchases were due to
 
the Greater Kuparuk Area and Western North Slope acquisitions.
 
 
Extensions and discoveries
: 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.
 
 
In 2017, extensions and discoveries in Lower 48
 
were primarily due to continued drilling success
 
in the Permian
Unconventional, Eagle Ford and Bakken.
 
 
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 interest in Barnett.
 
In 2017, Lower 48 sales were due to the disposition
 
of our interests in the San
Juan Basin and Panhandle assets, while Canada sales
 
were due to the disposition of a majority
 
of our western Canada
assets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
160
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed and Undeveloped
Consolidated operations
End of 2016
159
Revisions
16
Improved recovery
-
Purchases
-
Extensions and discoveries
96
Production
(21)
Sales
-
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
Equity affiliates
End of 2016
1,089
Revisions
-
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(23)
Sales
(1,066)
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
Total
 
company
End of 2016
1,248
End of 2017
250
End of 2018
236
End of 2019
282
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
161
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed
Consolidated operations
End of 2016
159
End of 2017
154
End of 2018
155
End of 2019
187
Equity affiliates
End of 2016
322
End of 2017
-
End of 2018
-
End of 2019
-
Undeveloped
Consolidated operations
End of 2016
-
End of 2017
96
End of 2018
81
End of 2019
95
Equity affiliates
End of 2016
767
End of 2017
-
End of 2018
-
End of 2019
-
 
 
Notable changes in proved bitumen reserves
 
in the three years ended December 31, 2019,
 
included:
 
 
 
Revisions
: 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 and 2017,
 
revisions were primarily due to higher
 
prices at Surmont.
 
 
Extensions and discoveries
: 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.
 
In 2017, extensions and discoveries were primarily
 
due to higher prices at Surmont, which allowed
undeveloped reserves previously de-booked due
 
to low prices to be recognized.
 
 
 
Sales
: In 2017, sales were due to the disposition of
 
our 50 percent interest in the FCCL Partnership
 
in
Canada.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
162
Years Ended
Total Proved
 
Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2016
1,294
1,570
2,864
393
528
444
241
4,470
Revisions
166
170
336
18
68
36
-
458
Improved recovery
6
-
6
-
-
-
-
6
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
41
378
419
97
-
7
-
523
Production
(77)
(144)
(221)
(37)
(79)
(81)
(8)
(426)
Sales
-
(621)
(621)
(217)
-
-
-
(838)
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
Equity affiliates
End of 2016
-
-
-
1,089
-
865
-
1,954
Revisions
-
-
-
-
-
18
-
18
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
31
-
31
Production
-
-
-
(23)
-
(69)
-
(92)
Sales
-
-
-
(1,066)
-
-
-
(1,066)
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
Total
 
company
End of 2016
1,294
1,570
2,864
1,482
528
1,309
241
6,424
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
Consolidated operations
End of 2016
1,203
1,165
2,368
391
365
309
241
3,674
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
Equity affiliates
End of 2016
-
-
-
322
-
820
-
1,142
End of 2017
-
-
-
-
-
802
-
802
End of 2018
-
-
-
-
-
796
-
796
End of 2019
-
-
-
-
-
761
-
761
Undeveloped
Consolidated operations
End of 2016
91
405
496
2
163
135
-
796
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
Equity affiliates
End of 2016
-
-
-
767
-
45
-
812
End of 2017
-
-
-
-
-
43
-
43
End of 2018
-
-
-
-
-
84
-
84
End of 2019
-
-
-
-
-
87
-
87
 
 
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
 
We had 1,327 MMBOE of PUDs at year-end 2019,
 
compared with 1,162 MMBOE at year-end 2018.
 
The following table
shows changes in total proved undeveloped reserves
 
for 2019:
 
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
End of 2018
1,162
Transfers to proved developed
(286)
Revisions
(5)
Improved recovery
7
Purchases
1
Extensions and discoveries
468
Sales
(20)
End of 2019
1,327
 
 
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 Asia Pacific/Middle East, Alaska, Europe
 
and Canada regions.
 
 
 
164
Downward revisions were driven by changes in
 
development timing of 166 MMBOE primarily
 
in Lower 48 and Canada,
largely offset by upward revisions for infill drilling of 147 MMBOE
 
primarily in Lower 48, Europe, Alaska and
 
Africa.
 
Extensions and discoveries were largely driven by an addition
 
of 358 MMBOE in Lower 48 for the continued development
 
of
unconventional plays. The remaining extensions
 
and discoveries were driven by the continued
 
development planned in Alaska,
Canada and Asia Pacific/Middle East.
 
 
Sales were due to the disposition of the U.K.
 
assets.
 
At December 31, 2019, our PUDs represented
 
25 percent of total proved reserves, compared
 
with 22 percent at December 31,
2018.
 
Costs incurred for the year ended December
 
31, 2019, relating to the development of PUDs
 
were $4.6 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 2019, more than 90 percent of total
 
PUDs were under development or scheduled for
 
development within five
years of initial disclosure. The remainder are to
 
be developed as parts of major projects ongoing
 
in our Canada, Asia
Pacific/Middle East and Europe regions.
 
All major development areas are currently producing
 
and are expected to have PUDs
convert to proved developed over time.
 
Of our total PUDs at year-end 2019, 81 percent are
 
in North America, and 95 percent of
these reserve volumes are planned for development
 
within five years of initial disclosure.
 
Results of Operations
 
 
The company’s results of operations from oil and gas activities
 
for the years 2019, 2018 and 2017 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
165
Results of Operations
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
166
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
167
Year Ended
Millions of Dollars
December 31, 2017
Lower
Total
 
 
Asia Pacific/
 
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
3,542
4,557
8,099
705
3,527
2,752
487
-
15,570
Transfers
4
-
4
-
-
411
-
-
415
Transportation costs
(706)
-
(706)
-
-
(80)
-
-
(786)
Other revenues
14
28
42
2,158
68
11
48
322
2,649
Total revenues
2,854
4,585
7,439
2,863
3,595
3,094
535
322
17,848
Production costs excluding taxes
947
1,607
2,554
604
770
566
44
(1)
4,537
Taxes other than income taxes
275
318
593
33
32
39
2
-
699
Exploration expenses
83
584
667
22
45
97
61
45
937
Depreciation, depletion and
 
amortization
730
2,685
3,415
438
1,234
1,283
16
-
6,386
Impairments
179
3,969
4,148
22
46
-
-
-
4,216
Other related expenses
(7)
62
55
7
57
60
6
-
185
Accretion
52
63
115
16
172
37
-
-
340
595
(4,703)
(4,108)
1,721
1,239
1,012
406
278
548
Income tax provision (benefit)
(669)
(2,401)
(3,070)
(651)
702
363
428
11
(2,217)
Results of operations
$
1,264
(2,302)
(1,038)
2,372
537
649
(22)
267
2,765
Equity affiliates
Sales
$
-
-
-
528
-
563
-
-
1,091
Transfers
-
-
-
-
-
1,398
-
-
1,398
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
5
-
-
-
-
5
Total revenues
-
-
-
533
-
1,961
-
-
2,494
Production costs excluding taxes
-
-
-
174
-
363
-
-
537
Taxes other than income taxes
-
-
-
7
-
604
-
-
611
Exploration expenses
-
-
-
1
-
1,699
-
-
1,700
Depreciation, depletion and
 
-
-
-
-
-
-
-
-
amortization
-
-
-
150
-
617
-
-
767
Impairments
-
-
-
-
-
1,717
-
-
1,717
Other related expenses
-
-
-
4
-
22
-
19
45
Accretion
-
-
-
2
-
11
-
-
13
-
-
-
195
-
(3,072)
-
(19)
(2,896)
Income tax provision (benefit)
-
-
-
26
-
(998)
-
13
(959)
Results of operations
$
-
-
-
169
-
(2,074)
-
(32)
(1,937)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
168
Statistics
 
Net Production
2019
2018
2017
Thousands of Barrels Daily
Crude Oil
 
Consolidated operations
Alaska
 
202
171
167
Lower 48
266
229
180
United States
468
400
347
Canada
1
1
3
Europe
100
113
122
Asia Pacific/Middle East
85
89
93
Africa
38
36
20
Total consolidated
 
operations
692
639
585
Equity affiliates—
Asia Pacific/Middle East
13
14
14
Total company
705
653
599
Greater Prudhoe Area
 
(Alaska)*
66
71
74
Natural Gas Liquids
Consolidated operations
Alaska
 
15
14
14
Lower 48
81
69
69
United States
96
83
83
Canada
-
1
9
Europe
7
8
8
Asia Pacific/Middle East
4
3
4
Total consolidated
 
operations
107
95
104
Equity affiliates—
Asia Pacific/Middle East
8
7
7
Total company
115
102
111
Greater Prudhoe Area
 
(Alaska)*
15
14
14
Bitumen
Consolidated operations—
Canada
60
66
59
Equity affiliates—
Canada
 
63
Total company
60
66
122
Natural Gas
Millions of Cubic Feet Daily
Consolidated operations
Alaska
7
6
7
Lower 48
622
596
898
United States
629
602
905
Canada
9
12
187
Europe
447
475
476
Asia Pacific/Middle East
637
626
687
Africa
31
28
8
Total consolidated
 
operations
1,753
1,743
2,263
Equity affiliates—
Asia Pacific/Middle East
1,052
1,031
1,007
Total company
2,805
2,774
3,270
Greater Prudhoe Area
 
(Alaska)*
4
5
5
*At year-end 2019, the Greater Prudhoe Area in Alaska contained more than 15% of total proved reserves.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
169
Average Sales
 
Prices
2019
2018
2017
Crude Oil Per Barrel
 
Consolidated operations
Alaska
$
55.85
60.23
42.69
Lower 48
55.30
62.99
47.36
United States
55.54
61.75
45.01
Canada
40.87
48.73
43.69
Europe
65.12
70.98
54.04
Asia Pacific/Middle East
65.02
70.93
54.38
Africa
64.47
69.83
55.11
Total international
64.85
70.67
54.16
Total consolidated
 
operations
58.51
65.01
48.70
Equity affiliates
—Asia Pacific/Middle East
61.32
72.49
54.76
Total operations
58.57
65.17
48.84
Natural Gas Liquids Per Barrel
 
Consolidated operations
Lower 48
$
16.83
27.30
22.20
United States
16.85
27.30
22.20
Canada
19.87
43.70
21.51
Europe
29.37
36.87
34.07
Asia Pacific/Middle East
37.85
47.20
41.37
Total international
32.29
40.00
30.34
Total consolidated
 
operations
18.73
29.03
24.21
Equity affiliates
—Asia Pacific/Middle East
36.70
45.69
38.74
Total operations
20.09
30.48
25.22
Bitumen Per Barrel
Consolidated operations—
Canada
$
31.72
22.29
21.43
Equity affiliates—
Canada
23.83
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
$
3.19
2.48
2.72
Lower 48
2.12
2.82
2.73
United States
2.12
2.82
2.73
Canada
0.49
1.00
1.93
Europe
4.92
7.79
5.72
Asia Pacific/Middle East
5.73
5.95
4.66
Africa
4.87
4.84
3.53
Total international
5.35
6.64
4.64
Total consolidated
 
operations
4.19
5.33
3.87
Equity affiliates
—Asia Pacific/Middle East
6.29
6.06
4.27
Total operations
4.99
5.60
4.00
Average sales prices for Alaska crude oil and Asia Pacific/Middle East 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
170
2019
2018
2017
Average Production
 
Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
$
15.52
14.20
14.26
Lower 48
9.59
10.58
11.03
United States
11.52
11.73
12.04
Canada
16.53
16.32
16.22
Europe
11.22
11.73
10.09
Asia Pacific/Middle East
8.74
9.03
7.31
Africa
4.46
4.14
5.74
Total international
10.26
10.72
9.99
Total consolidated operations
10.99
11.26
11.05
Equity affiliates
Canada
7.57
Asia Pacific/Middle East
4.68
4.56
5.26
Total equity affiliates
4.68
4.56
5.84
Average Production
 
Costs Per Barrel—Bitumen
Consolidated operations—
Canada
$
13.74
13.59
14.63
Equity affiliates—
Canada
18.74
Taxes
 
Other Than Income Taxes Per Barrel
 
of Oil Equivalent
Consolidated operations
Alaska
$
3.87
5.26
4.14
Lower 48
2.65
2.98
2.18
United States
3.05
3.71
2.80
Canada
0.78
0.82
0.89
Europe
0.48
0.45
0.42
Asia Pacific/Middle East
0.76
1.33
0.50
Africa
0.19
0.20
0.26
Total international
0.60
0.82
0.53
Total consolidated operations
2.03
2.37
1.70
Equity affiliates
Canada
0.30
Asia Pacific/Middle East
11.46
11.41
8.76
Total equity affiliates
11.46
11.41
6.64
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
8.80
9.07
10.99
Lower 48
17.03
15.73
18.44
United States
14.35
13.60
16.10
Canada
10.00
12.25
11.76
Europe
12.75
14.66
16.18
Asia Pacific/Middle East
16.55
16.58
16.58
Africa
2.36
2.21
2.09
Total international
12.99
14.06
14.96
Total consolidated operations
13.78
13.82
15.55
Equity affiliates
Canada
6.52
Asia Pacific/Middle East
8.09
9.09
8.94
Total equity affiliates
8.09
9.09
8.34
*Includes bitumen.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
171
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, 2019,
 
2018 and 2017.
 
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
2019
2018
2017
2019
2018
2017
Exploratory
Consolidated operations
Alaska
7
6
-
-
-
-
Lower 48
35
45
13
6
1
3
United States
42
51
13
6
1
3
Canada
-
2
13
-
-
-
Europe
1
*
*
1
*
*
Asia Pacific/Middle East
1
2
1
1
-
1
Africa
-
-
-
-
*
-
Other areas
-
-
-
-
-
1
Total consolidated
 
operations
44
55
27
8
1
5
Equity affiliates
Asia Pacific/Middle East
8
6
14
-
2
-
Total equity affiliates
8
6
14
-
2
-
Development
Consolidated operations
 
 
Alaska
12
11
9
-
-
-
Lower 48
255
254
161
-
-
-
United States
267
265
170
-
-
-
Canada
2
1
13
-
-
-
Europe
6
9
7
-
-
-
Asia Pacific/Middle East
21
12
8
-
-
-
Africa
2
1
-
-
-
-
Other areas
-
-
-
-
-
-
Total consolidated
 
operations
298
288
198
-
-
-
Equity affiliates
Canada
-
-
19
-
-
-
Asia Pacific/Middle East
106
75
84
-
-
-
Other areas
-
-
-
-
-
-
Total equity affiliates
106
75
103
-
-
-
*Our total proportionate interest was less than one.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
172
The table below represents the status of our wells
 
drilling at December 31, 2019, 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, 2019.
Wells at December 31, 2019
Productive
In Progress
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Consolidated operations
Alaska
4
4
1,656
997
-
-
Lower 48
349
170
10,070
4,547
4,329
1,704
United States
353
174
11,726
5,544
4,329
1,704
Canada
32
32
186
93
31
27
Europe
19
1
469
79
55
2
Asia Pacific/Middle East
12
6
302
143
56
28
Africa
13
2
840
137
7
1
Other areas
14
7
-
-
-
-
Total consolidated
 
operations
443
222
13,523
5,996
4,478
1,762
Equity affiliates
Asia Pacific/Middle East
325
79
-
-
4,307
1,051
Total equity affiliates
325
79
-
-
4,307
1,051
 
 
Acreage at December 31, 2019
Thousands of Acres
Developed
Undeveloped
Gross
Net
Gross
Net
Consolidated operations
Alaska
651
467
1,331
1,320
Lower 48
2,569
2,012
10,337
8,396
United States
3,220
2,479
11,668
9,716
Canada
206
126
3,270
1,798
Europe
430
50
2,102
610
Asia Pacific/Middle East
1,538
721
9,910
5,735
Africa
358
58
12,545
2,049
Other areas
-
-
1,400
742
Total consolidated
 
operations
5,752
3,434
40,895
20,650
Equity affiliates
Asia Pacific/Middle East
933
229
3,723
840
Total equity affiliates
933
229
3,723
840
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
173
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
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
2017
Consolidated operations
Unproved property acquisition
$
18
267
285
76
-
15
-
-
376
Proved property acquisition
-
35
35
-
-
-
-
-
35
18
302
320
76
-
15
-
-
411
Exploration
74
399
473
56
52
139
61
42
823
Development
736
1,559
2,295
102
784
388
10
-
3,579
$
828
2,260
3,088
234
836
542
71
42
4,813
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
6
-
38
-
-
44
Development
-
-
-
150
-
403
-
-
553
$
-
-
-
156
-
441
-
-
597
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
174
Capitalized Costs
At December 31
Millions of Dollars
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
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
2018
Consolidated operations
Proved property
$
20,154
35,269
55,423
5,946
23,520
14,866
902
-
100,657
Unproved property
1,184
1,125
2,309
1,083
188
874
119
89
4,662
21,338
36,394
57,732
7,029
23,708
15,740
1,021
89
105,319
Accumulated depreciation,
depletion and amortization
9,055
23,999
33,054
1,692
16,591
9,974
342
9
61,662
$
12,283
12,395
24,678
5,337
7,117
5,766
679
80
43,657
Equity affiliates
Proved property
$
-
-
-
-
-
9,990
-
-
9,990
Unproved property
-
-
-
-
-
2,162
-
-
2,162
-
-
-
-
-
12,152
-
-
12,152
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
5,960
-
-
5,960
$
-
-
-
-
-
6,192
-
-
6,192
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
175
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
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
176
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
 
 
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2017
Consolidated operations
Future cash inflows
$
44,969
44,556
89,525
5,479
23,137
15,207
13,181
146,529
Less:
Future production costs
29,524
18,947
48,471
4,417
8,128
5,398
1,401
67,815
Future development costs
7,255
10,881
18,136
696
8,758
2,511
537
30,638
Future income tax provisions
53
2,375
2,428
-
3,333
2,459
10,356
18,576
Future net cash flows
8,137
12,353
20,490
366
2,918
4,839
887
29,500
10 percent annual discount
2,712
4,358
7,070
78
289
1,032
422
8,891
Discounted future net cash flows
$
5,425
7,995
13,420
288
2,629
3,807
465
20,609
Equity affiliates
Future cash inflows
$
-
-
-
-
-
23,222
-
23,222
Less:
Future production costs
-
-
-
-
-
12,984
-
12,984
Future development costs
-
-
-
-
-
1,444
-
1,444
Future income tax provisions
-
-
-
-
-
2,083
-
2,083
Future net cash flows
-
-
-
-
-
6,711
-
6,711
10 percent annual discount
-
-
-
-
-
2,316
-
2,316
Discounted future net cash flows
$
-
-
-
-
-
4,395
-
4,395
Total
 
company
Discounted future net cash flows
$
5,425
7,995
13,420
288
2,629
8,202
465
25,004
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
177
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
Consolidated Operations
Equity Affiliates
Total Company
2019
2018
2017
2019
2018
2017
2019
2018
2017
Discounted future net cash flows
 
at the beginning of the year
$
35,434
20,609
8,151
7,929
4,395
3,937
43,363
25,004
12,088
Changes during the year
Revenues less production
 
costs for the year
(13,424)
(14,909)
(9,844)
(1,673)
(1,651)
(1,341)
(15,097)
(16,560)
(11,185)
Net change in prices and
production costs
(13,538)
25,391
19,310
(422)
4,559
2,750
(13,960)
29,950
22,060
Extensions, discoveries and
improved recovery, less
estimated future costs
2,985
4,574
1,445
260
382
(4)
3,245
4,956
1,441
Development costs for the year
5,333
5,197
3,653
239
271
426
5,572
5,468
4,079
Changes in estimated future
development costs
559
(1,141)
1,225
(21)
14
(64)
538
(1,127)
1,161
Purchases of reserves in place,
 
less estimated future costs
10
3,033
-
-
-
-
10
3,033
-
Sales of reserves in place,
 
less estimated future costs
(1,997)
(1,531)
(855)
-
-
(786)
(1,997)
(1,531)
(1,641)
Revisions of previous quantity
estimates
2,099
(365)
2,300
69
62
(648)
2,168
(303)
1,652
Accretion of discount
5,144
3,055
1,313
869
485
413
6,013
3,540
1,726
Net change in income taxes
4,767
(8,479)
(6,089)
(80)
(588)
(288)
4,687
(9,067)
(6,377)
Total changes
(8,062)
14,825
12,458
(759)
3,534
458
(8,821)
18,359
12,916
Discounted future net cash flows
at year end
$
27,372
35,434
20,609
7,170
7,929
4,395
34,542
43,363
25,004
 
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
178
Selected Quarterly Financial Data
(Unaudited)
Millions of Dollars
Per Share of Common Stock
Sales and
Net Income
Net Income (Loss)
 
Other
Income (Loss)
Net
(Loss)
Attributable
Operating
Before
Income
Attributable to
to ConocoPhillips
 
Revenues
Income Taxes
(Loss)
ConocoPhillips
Basic
Diluted
2019
First
$
9,150
2,687
1,846
1,833
1.61
1.60
Second
7,953
2,058
1,597
1,580
1.40
1.40
Third
7,756
3,493
3,071
3,056
2.76
2.74
Fourth
7,708
1,286
743
720
0.66
0.66
2018
First
$
 
8,798
1,776
900
888
0.75
0.75
Second
8,504
2,619
1,654
1,640
1.40
1.39
Third
9,449
2,906
1,873
1,861
1.60
1.59
Fourth
9,666
2,672
1,878
1,868
1.62
1.61
For additional information on the commodity price environment, see the
 
Business Environment and Executive Overview section of Management's Discussion
 
and
Analysis of Financial Condition and Results of Operations.
 
 
179
Supplementary Information—Condensed Consolidating
 
Financial Information
 
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company
 
and Burlington Resources
LLC, with respect to publicly held debt securities.
 
ConocoPhillips Company is 100 percent owned
 
by
ConocoPhillips.
 
Burlington Resources LLC is 100 percent
 
owned by ConocoPhillips Company.
 
ConocoPhillips and/or ConocoPhillips Company
 
have fully and unconditionally guaranteed
 
the payment
obligations of Burlington Resources LLC, with respect
 
to its publicly held debt securities.
 
Similarly,
ConocoPhillips has fully and unconditionally
 
guaranteed the payment obligations of ConocoPhillips
 
Company
with respect to its publicly held debt securities.
 
In addition, ConocoPhillips Company
 
has fully and
unconditionally guaranteed the payment obligations
 
of ConocoPhillips with respect to its publicly
 
held debt
securities.
 
All guarantees are joint and several.
 
The following condensed consolidating financial
 
information
presents the results of operations, financial position
 
and cash flows for:
 
 
ConocoPhillips, ConocoPhillips Company and
 
Burlington Resources LLC (in each case, reflecting
investments in subsidiaries utilizing the equity
 
method of accounting).
 
All other nonguarantor subsidiaries of ConocoPhillips.
 
The consolidating adjustments necessary to present
 
ConocoPhillips’ results on a consolidated
 
basis.
 
In 2017, ConocoPhillips Company received a $
9.8
billion return of capital and a $
1.4
 
billion loan repayment
from nonguarantor subsidiaries to settle certain
 
accumulated intercompany balances.
 
These transactions had
no impact on our consolidated financial statements.
 
In 2017, ConocoPhillips received a $
7.8
 
billion return of capital and a $
0.2
 
billion return of earnings from
ConocoPhillips Company to settle certain
 
accumulated intercompany balances.
 
These transactions had no
impact on our consolidated financial statements.
 
In 2018, ConocoPhillips Company received a $
4.8
 
billion return of earnings and a $
2.4
 
billion loan repayment
from nonguarantor subsidiaries to settle certain
 
accumulated intercompany balances.
 
These transactions had
no impact on our consolidated financial statements.
 
 
In 2018, ConocoPhillips received a $
3.5
 
billion return of capital and a $
1.0
 
billion return of earnings from
ConocoPhillips Company to settle certain
 
accumulated intercompany balances.
 
These transactions had no
impact on our consolidated financial statements.
 
In 2019, ConocoPhillips received a $
2.4
 
billion return of capital and a $
1.7
 
billion return of earnings from
ConocoPhillips Company to settle certain
 
accumulated intercompany balances.
 
This transaction had no impact
on our consolidated financial statements.
 
 
In 2019, ConocoPhillips Company received a $
4.5
 
billion return of earnings and a $
4.2
 
billion return of capital
from nonguarantor subsidiaries to settle certain
 
accumulated intercompany balances.
 
These transactions had
no impact on our consolidated financial statements.
 
In 2019, Burlington Resources LLC received
 
a $
3.2
 
billion return of earnings from nonguarantor
 
subsidiaries
to settle certain accumulated intercompany balances.
 
These transactions had no impact on our consolidated
financial statements.
 
This condensed consolidating financial information
 
should be read in conjunction with the accompanying
consolidated financial statements and notes.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
180
Millions of Dollars
Year Ended December 31,
 
2019
Income Statement
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Revenues and Other Income
Sales and other operating revenues
$
-
14,510
-
18,057
-
32,567
Equity in earnings of affiliates
7,419
5,281
1,610
775
(14,306)
779
Gain (loss) on dispositions
-
2,786
-
(820)
-
1,966
Other income
1
875
5
477
-
1,358
Intercompany revenues
-
113
40
5,542
(5,695)
-
Total Revenues and Other
 
Income
7,420
23,565
1,655
24,031
(20,001)
36,670
Costs and Expenses
Purchased commodities
-
12,838
-
4,038
(5,034)
11,842
Production and operating expenses
1
1,380
1
4,345
(405)
5,322
Selling, general and administrative expenses
9
421
-
131
(5)
556
Exploration expenses
-
422
-
321
-
743
Depreciation, depletion and amortization
-
596
-
5,494
-
6,090
Impairments
-
157
-
248
-
405
Taxes other than income taxes
-
139
-
814
-
953
Accretion on discounted liabilities
-
16
-
310
-
326
Interest and debt expense
283
544
133
69
(251)
778
Foreign currency transaction losses
-
21
-
45
-
66
Other expenses
-
60
-
5
-
65
Total Costs and Expenses
293
16,594
134
15,820
(5,695)
27,146
Income before income taxes
7,127
6,971
1,521
8,211
(14,306)
9,524
Income tax provision (benefit)
(62)
(448)
(46)
2,823
-
2,267
Net income
7,189
7,419
1,567
5,388
(14,306)
7,257
Less: net income attributable to noncontrolling interests
-
-
-
(68)
-
(68)
Net Income Attributable to ConocoPhillips
$
7,189
7,419
1,567
5,320
(14,306)
7,189
Comprehensive Income Attributable to ConocoPhillips
$
7,935
8,165
1,873
6,058
(16,096)
7,935
Income Statement
Year Ended December 31,
 
2018
Revenues and Other Income
Sales and other operating revenues
$
-
16,113
-
20,304
-
36,417
Equity in earnings of affiliates
6,503
8,142
1,953
1,072
(16,596)
1,074
Gain on dispositions
-
239
-
824
-
1,063
Other income (loss)
-
(384)
-
557
-
173
Intercompany revenues
35
162
43
5,627
(5,867)
-
Total Revenues and Other
 
Income
6,538
24,272
1,996
28,384
(22,463)
38,727
Costs and Expenses
Purchased commodities
-
14,591
-
5,131
(5,428)
14,294
Production and operating expenses
-
1,023
4
4,245
(59)
5,213
Selling, general and administrative expenses
8
289
-
109
(5)
401
Exploration expenses
-
170
-
199
-
369
Depreciation, depletion and amortization
-
584
-
5,372
-
5,956
Impairments
-
(10)
-
37
-
27
Taxes other than income taxes
-
143
-
905
-
1,048
Accretion on discounted liabilities
-
17
-
336
-
353
Interest and debt expense
295
613
46
156
(375)
735
Foreign currency transaction (gains) losses
46
(12)
116
(167)
-
(17)
Other expenses
-
349
6
20
-
375
Total Costs and Expenses
349
17,757
172
16,343
(5,867)
28,754
Income before income taxes
6,189
6,515
1,824
12,041
(16,596)
9,973
Income tax provision (benefit)
(68)
12
(41)
3,765
-
3,668
Net income
6,257
6,503
1,865
8,276
(16,596)
6,305
Less: net income attributable to noncontrolling interests
-
-
-
(48)
-
(48)
Net Income Attributable to ConocoPhillips
$
6,257
6,503
1,865
8,228
(16,596)
6,257
Comprehensive Income Attributable to ConocoPhillips
$
5,654
5,900
1,364
7,961
(15,225)
5,654
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
181
Millions of Dollars
Year Ended December 31,
 
2017
Income Statement
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Revenues and Other Income
Sales and other operating revenues
$
-
12,433
-
16,673
-
29,106
Equity in earnings (losses) of affiliates
(454)
2,047
886
770
(2,477)
772
Gain on dispositions
-
916
-
1,261
-
2,177
Other income
2
35
-
492
-
529
Intercompany revenues
48
291
13
3,369
(3,721)
-
Total Revenues and Other
 
Income
(404)
15,722
899
22,565
(6,198)
32,584
Costs and Expenses
Purchased commodities
-
11,145
-
4,580
(3,250)
12,475
Production and operating expenses
-
813
-
4,366
(17)
5,162
Selling, general and administrative expenses
9
342
-
82
(6)
427
Exploration expenses
-
542
-
392
-
934
Depreciation, depletion and amortization
-
855
-
5,990
-
6,845
Impairments
-
1,159
-
5,442
-
6,601
Taxes other than income taxes
-
140
1
668
-
809
Accretion on discounted liabilities
-
32
-
330
-
362
Interest and debt expense
420
664
52
410
(448)
1,098
Foreign currency transaction (gains) losses
(43)
11
(137)
204
-
35
Other expenses
267
190
-
(6)
-
451
Total Costs and Expenses
653
15,893
(84)
22,458
(3,721)
35,199
Income (Loss) before income taxes
(1,057)
(171)
983
107
(2,477)
(2,615)
Income tax provision (benefit)
(202)
283
(337)
(1,566)
-
(1,822)
Net income (loss)
(855)
(454)
1,320
1,673
(2,477)
(793)
Less: net income attributable to noncontrolling interests
-
-
-
(62)
-
(62)
Net Income (Loss) Attributable to ConocoPhillips
$
(855)
(454)
1,320
1,611
(2,477)
(855)
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
(180)
221
1,672
2,275
(4,168)
(180)
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
182
Millions of Dollars
At December 31, 2019
Balance Sheet
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Assets
Cash and cash equivalents
$
-
3,439
-
1,649
-
5,088
Short-term investments
-
2,670
-
358
-
3,028
Accounts and notes receivable
5
2,088
2
3,881
(2,575)
3,401
Investment in Cenovus Energy
-
2,111
-
-
-
2,111
Inventories
-
168
-
858
-
1,026
Prepaid expenses and other current assets
1
352
-
1,906
-
2,259
Total Current Assets
6
10,828
2
8,652
(2,575)
16,913
Investments, loans and long-term receivables*
34,076
44,969
11,662
15,612
(97,413)
8,906
Net properties, plants and equipment
-
3,552
-
38,717
-
42,269
Other assets
3
765
253
2,210
(805)
2,426
Total Assets
$
34,085
60,114
11,917
65,191
(100,793)
70,514
Liabilities and Stockholders’ Equity
Accounts payable
$
-
2,670
21
3,084
(2,575)
3,200
Short-term debt
(3)
4
13
91
-
105
Accrued income and other taxes
-
79
-
951
-
1,030
Employee benefit obligations
-
508
-
155
-
663
Other accruals
84
408
35
1,518
-
2,045
Total Current Liabilities
81
3,669
69
5,799
(2,575)
7,043
Long-term debt
3,794
6,670
2,129
2,197
-
14,790
Asset retirement obligations and accrued environmental costs
-
322
-
5,030
-
5,352
Deferred income taxes
-
-
-
5,438
(804)
4,634
Employee benefit obligations
-
1,329
-
452
-
1,781
Other liabilities and deferred credits*
1,787
7,514
826
9,271
(17,534)
1,864
Total Liabilities
5,662
19,504
3,024
28,187
(20,913)
35,464
Retained earnings
33,184
21,898
2,164
10,481
(27,985)
39,742
Other common stockholders’ equity
(4,761)
18,712
6,729
26,454
(51,895)
(4,761)
Noncontrolling interests
-
-
-
69
-
69
Total Liabilities and Stockholders’
 
Equity
$
34,085
60,114
11,917
65,191
(100,793)
70,514
Balance Sheet
At December 31, 2018
Assets
Cash and cash equivalents
$
-
1,428
-
4,487
-
5,915
Short-term investments
-
-
-
248
-
248
Accounts and notes receivable
28
5,646
78
6,707
(8,392)
4,067
Investment in Cenovus Energy
-
1,462
-
-
-
1,462
Inventories
-
184
-
823
-
1,007
Prepaid expenses and other current assets
1
267
-
307
-
575
Total Current Assets
29
8,987
78
12,572
(8,392)
13,274
Investments, loans and long-term receivables*
29,942
47,062
15,199
16,926
(99,465)
9,664
Net properties, plants and equipment
-
4,367
-
41,796
(465)
45,698
Other assets
4
642
227
1,269
(798)
1,344
Total Assets
$
29,975
61,058
15,504
72,563
(109,120)
69,980
Liabilities and Stockholders’ Equity
Accounts payable
$
-
5,098
76
7,113
(8,392)
3,895
Short-term debt
(3)
12
13
99
(9)
112
Accrued income and other taxes
-
85
-
1,235
-
1,320
Employee benefit obligations
-
638
-
171
-
809
Other accruals
85
587
35
552
-
1,259
Total Current Liabilities
82
6,420
124
9,170
(8,401)
7,395
Long-term debt
3,791
7,151
2,143
2,249
(478)
14,856
Asset retirement obligations and accrued environmental costs
-
415
-
7,273
-
7,688
Deferred income taxes
-
-
-
5,819
(798)
5,021
Employee benefit obligations
-
1,340
-
424
-
1,764
Other liabilities and deferred credits*
725
9,277
839
8,126
(17,775)
1,192
Total Liabilities
4,598
24,603
3,106
33,061
(27,452)
37,916
Retained earnings
27,512
18,511
1,113
9,764
(22,890)
34,010
Other common stockholders’ equity
(2,135)
17,944
11,285
29,613
(58,778)
(2,071)
Noncontrolling interests
-
-
-
125
-
125
Total Liabilities and Stockholders’
 
Equity
$
29,975
61,058
15,504
72,563
(109,120)
69,980
*Includes intercompany loans.
 
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
183
Millions of Dollars
Year Ended December 31,
 
2019
Statement of Cash Flows
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
$
1,457
7,986
3,207
9,803
(11,349)
11,104
Cash Flows From Investing Activities
Capital expenditures and investments
-
(2,517)
-
(5,714)
1,595
(6,636)
Working capital changes associated
 
with investing activities
-
37
-
(140)
-
(103)
Proceeds from asset dispositions
2,374
7,047
769
1,055
(8,233)
3,012
Net purchases of investments
-
(2,803)
-
(107)
-
(2,910)
Long-term advances/loans—related parties
-
(812)
-
-
812
-
Collection of advances/loans—related parties
-
141
-
147
(161)
127
Intercompany cash management
1,060
(2,849)
1,402
387
-
-
Other
-
(149)
-
41
-
(108)
Net Cash Provided by (Used in) Investing Activities
3,434
(1,905)
2,171
(4,331)
(5,987)
(6,618)
Cash Flows From Financing Activities
Issuance of debt
-
-
-
812
(812)
-
Repayment of debt
-
(21)
-
(220)
161
(80)
Issuance of company common stock
105
-
-
-
(135)
(30)
Repurchase of company common stock
(3,500)
-
-
-
-
(3,500)
Dividends paid
(1,500)
(4,034)
(454)
(7,097)
11,585
(1,500)
Other
4
-
(4,924)
(1,736)
6,537
(119)
Net Cash Used in Financing Activities
(4,891)
(4,055)
(5,378)
(8,241)
17,336
(5,229)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
-
(11)
-
(35)
-
(46)
Net Change in Cash, Cash Equivalents and Restricted Cash
-
2,015
-
(2,804)
-
(789)
Cash, cash equivalents and restricted cash at beginning of period
-
1,428
-
4,723
-
6,151
Cash, Cash Equivalents and Restricted Cash at End of Period
$
-
3,443
-
1,919
-
5,362
Statement of Cash Flows
Year Ended December 31,
 
2018*
Cash Flows From Operating Activities
Net Cash
 
Provided by Operating Activities
$
860
4,019
838
14,132
(6,915)
12,934
Cash Flows From Investing Activities
Capital expenditures and investments
-
(980)
(603)
(5,777)
610
(6,750)
Working capital changes associated
 
with investing activities
-
(110)
-
42
-
(68)
Proceeds from asset dispositions
3,457
666
1,926
705
(5,672)
1,082
Net sales of short-term investments
-
-
-
1,620
-
1,620
Long-term advances/loans—related parties
 
-
(126)
(173)
(10)
309
-
Collection of advances/loans—related parties
589
3,432
212
129
(4,243)
119
Intercompany cash management
(803)
3,504
(2,150)
(551)
-
-
Other
-
151
-
3
-
154
Net Cash Provided by (Used in) Investing Activities
3,243
6,537
(788)
(3,839)
(8,996)
(3,843)
Cash Flows From Financing Activities
Issuance
 
of debt
-
10
-
299
(309)
-
Repayment of debt
-
(4,865)
(53)
(4,320)
4,243
(4,995)
Issuance of company common stock
254
-
-
-
(133)
121
Repurchase of company common stock
(2,999)
-
-
-
-
(2,999)
Dividends paid
(1,363)
(1,043)
-
(6,057)
7,100
(1,363)
Other
5
(3,468)
-
(1,670)
5,010
(123)
Net Cash Used in Financing Activities
(4,103)
(9,366)
(53)
(11,748)
15,911
(9,359)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
-
4
-
(121)
-
(117)
Net Change in Cash, Cash Equivalents and Restricted Cash
-
1,194
(3)
(1,576)
-
(385)
Cash, cash equivalents and restricted cash at beginning of period
-
234
3
6,299
-
6,536
Cash, Cash Equivalents and Restricted Cash at End of Period
$
-
1,428
-
4,723
-
6,151
*Revised to reclassify certain intercompany distributions from Operating Activities to 'Proceeds from asset dispositions' within Investing Activities based on the nature of the distributions.
 
There was no impact to Total Consolidated results.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
184
Millions of Dollars
Year Ended December 31,
 
2017
Statement of Cash Flows
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
$
71
1,183
2,971
5,904
(3,052)
7,077
Cash Flows From Investing Activities
Capital expenditures and investments
-
(1,663)
(4,351)
(3,795)
5,218
(4,591)
Working capital changes associated
 
with investing activities
-
194
-
(62)
-
132
Proceeds from asset dispositions
7,765
11,146
12,178
12,796
(30,025)
13,860
Net purchases of short-term investments
-
-
-
(1,790)
-
(1,790)
Long-term advances/loans—related parties
-
(214)
(65)
(20)
299
-
Collection of advances/loans—related parties
658
1,527
389
2,196
(4,655)
115
Intercompany cash management
1,151
101
(1,341)
89
-
-
Other
-
(8)
-
44
-
36
Net Cash Provided by Investing Activities
9,574
11,083
6,810
9,458
(29,163)
7,762
Cash Flows From Financing Activities
Issuance of debt
-
20
-
279
(299)
-
Repayment of debt
(5,459)
(4,411)
-
(2,661)
4,655
(7,876)
Issuance of company common stock
115
-
-
-
(178)
(63)
Repurchase of company common stock
(3,000)
-
-
-
-
(3,000)
Dividends paid
(1,305)
(235)
-
(2,995)
3,230
(1,305)
Other
4
(7,765)
(9,781)
(7,377)
24,807
(112)
Net Cash Used in Financing Activities
(9,645)
(12,391)
(9,781)
(12,754)
32,215
(12,356)
Effect of Exchange Rate Changes on Cash and Cash Equivalents
-
1
(2)
233
-
232
Net Change in Cash and Cash Equivalents
-
(124)
(2)
2,841
-
2,715
Cash and cash equivalents at beginning of period
-
358
5
3,247
-
3,610
Cash and Cash Equivalents at End of Period
$
-
234
3
6,088
-
6,325
See Notes to Consolidated Financial Statements.
 
185
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, 2019,
 
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, 2019.
 
There have been no changes in our internal
 
control over financial reporting, as defined
 
in Rule 13a-15(f) of the
Act, in the period covered by this report that
 
have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
 
Management’s Annual Report on Internal Control Over Financial
 
Reporting
 
This report is included in Item 8 on page
 
and is incorporated herein by reference.
 
Report of Independent Registered Public Accounting
 
Firm
 
 
This report is included in Item 8 on page
 
and is incorporated herein by reference.
 
 
Item 9B.
 
OTHER INFORMATION
 
None.
 
186
PART
 
III
 
 
Item 10.
 
DIRECTORS, EXECUTIVE OFFICERS AND
 
CORPORATE GOVERNANCE
 
 
Information regarding our executive officers appears in
 
Part I of this report on page 29.
 
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
2020 Annual Meeting of Stockholders, to be
 
filed pursuant to Regulation 14A on or before
 
April 30, 2020, 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 2020
Annual Meeting of Stockholders, to be filed pursuant
 
to Regulation 14A on or before April 30,
 
2020, 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 2020
Annual Meeting of Stockholders, to be filed pursuant
 
to Regulation 14A on or before April 30,
 
2020, 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 2020
Annual Meeting of Stockholders, to be filed pursuant
 
to Regulation 14A on or before April 30,
 
2020, 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 2020
Annual Meeting of Stockholders, to be filed pursuant
 
to Regulation 14A on or before April 30,
 
2020, 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 2020 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
187
PART
 
IV
 
 
Item 15.
 
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
 
 
(a)
 
1.
 
Financial Statements and Supplementary
 
Data
The financial statements and supplementary information
 
listed in the Index to Financial Statements,
which appears on page
, are filed as part of this annual report.
 
 
2.
 
Financial Statement Schedules
Schedule II—Valuation and Qualifying Accounts, appears below.
 
All other schedules are omitted
because they are not required, not significant, not
 
applicable or the information is shown in another
schedule, the financial statements or the notes to
 
consolidated financial statements.
 
 
3.
 
Exhibits
The exhibits listed in the Index to Exhibits, which
 
appears on pages
 
through 196, are filed as part
of this annual report.
 
SCHEDULE II—VALUATION
 
AND QUALIFYING ACCOUNTS (Consolidated)
ConocoPhillips
Millions of Dollars
Balance at
Charged to
Balance at
Description
January 1
Expense
Other
(a)
Deductions
December 31
2019
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
25
5
-
(17)
(b)
13
Deferred tax asset valuation allowance
3,040
7,376
(26)
(176)
10,214
Included in other liabilities:
Restructuring accruals
48
(1)
-
(24)
(c)
23
2018
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
4
23
-
(2)
(b)
25
Deferred tax asset valuation allowance
1,254
2,067
(8)
(273)
3,040
Included in other liabilities:
Restructuring accruals
53
70
(2)
(73)
(c)
48
2017
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
5
2
-
(3)
(b)
4
Deferred tax asset valuation allowance
675
560
19
-
1,254
Included in other liabilities:
Restructuring accruals
80
65
1
(93)
(c)
53
(a)Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements.
(b)Amounts charged off less recoveries of amounts previously charged off.
(c)Benefit payments.
See Note 19
Income Taxes, in the Notes to Consolidated Financial Statements, for additional information related to our deferred
tax asset valuation allowance.
 
 
 
188
CONOCOPHILLIPS
 
 
 
INDEX TO EXHIBITS
 
Exhibit
 
Number
 
Description
 
2.1
 
 
2.2†‡
 
2.3†‡
 
 
3.1
 
 
3.2
 
 
3.3
 
 
 
ConocoPhillips and its subsidiaries are parties
 
to several debt instruments under which the total
amount of securities authorized does not exceed
 
10 percent of the total assets of ConocoPhillips
 
and
its subsidiaries on a consolidated basis.
 
Pursuant to paragraph 4(iii)(A) of Item 601(b)
 
of
Regulation S-K, ConocoPhillips agrees to furnish
 
a copy of such instruments to the SEC upon
request.
 
4.1*
 
 
10.1
 
 
 
10.2
 
 
 
 
 
Exhibit
Number
 
Description
189
10.3
 
 
10.4
 
 
10.5
 
 
10.6
 
 
10.7
 
 
10.8
 
 
10.9
 
 
10.10.1*
 
 
10.10.2
 
 
 
 
10.11.1*
 
 
10.11.2*
 
 
10.12
 
 
10.13
 
 
10.14
 
 
 
 
Exhibit
Number
 
Description
190
10.15
 
 
10.16.1
 
 
10.16.2
 
 
10.16.3
 
 
10.16.4
 
 
 
10.16.5
 
 
 
10.16.6
 
 
 
10.16.7
 
 
 
10.16.8
 
 
 
10.17.1
 
 
 
10.17.2
 
 
10.18
 
 
10.19.1*
 
 
 
Exhibit
Number
 
Description
191
 
10.19.2*
 
 
10.20
 
 
 
10.21
 
 
10.22.1
 
 
10.22.2
 
 
10.22.3
 
 
10.23
 
 
10.24
 
 
10.25.1
 
 
10.25.2
 
 
10.25.3
 
 
10.25.4
 
 
 
Exhibit
Number
 
Description
192
 
10.25.5
 
 
10.25.6
 
 
10.25.7
 
 
10.25.8
 
 
10.25.9
 
 
10.25.10
 
 
 
 
10.25.11
 
 
 
 
10.25.12
 
 
 
10.25.13
 
 
 
10.25.14
 
 
 
 
 
Exhibit
Number
 
Description
193
10.25.15
 
 
10.25.16
 
 
10.25.17
 
 
 
10.25.18
 
 
 
10.25.19
 
 
 
10.26.1
 
 
10.26.2
 
 
10.26.3
 
 
10.26.4
 
 
10.26.5
 
 
Exhibit
Number
 
Description
194
 
 
10.26.6
 
 
10.26.7
 
 
 
 
 
10.26.8
 
 
 
 
 
 
10.26.9
 
 
 
 
 
 
 
10.26.10
 
 
 
 
 
 
10.26.11
 
 
 
 
 
 
10.26.12
 
 
 
 
 
10.26.13
 
 
 
 
 
10.26.14
 
 
 
 
Exhibit
Number
 
Description
195
10.26.15
 
 
 
 
10.27*
 
 
 
10.28
 
 
10.29
 
 
10.30
 
 
10.31
 
 
10.32
 
 
10.33
 
 
10.34
 
 
10.35
 
 
10.36
 
 
10.37
 
 
 
 
Exhibit
Number
 
Description
196
10.38
 
 
 
10.40
 
 
21*
 
 
23.1*
 
 
23.2*
 
 
31.1*
 
 
31.2*
 
 
32*
 
 
99*
 
 
 
101.INS*
 
Inline XBRL Instance Document.
 
101.SCH*
 
Inline XBRL Schema Document.
 
101.CAL*
 
Inline XBRL Calculation Linkbase Document.
 
101.DEF*
 
Inline XBRL Definition Linkbase Document.
 
101.LAB*
 
Inline XBRL Labels Linkbase Document.
 
101.PRE*
 
Inline XBRL Presentation Linkbase Document.
 
104*
 
Cover Page Interactive Data File (formatted as Inline XBRL
 
and contained in Exhibit 101).
 
*
Filed herewith.
 
The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K.
 
ConocoPhillips agrees to
furnish a copy of any schedule omitted from this exhibit to the SEC upon request.
 
ConocoPhillips has previously been granted confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2
under the Securities Exchange Act of 1934, as amended.
 
 
 
 
 
 
 
 
197
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 18, 2020
/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 18, 2020, 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/ Don E. Wallette, Jr.
Executive Vice President and
Don E. Wallette, Jr.
Chief Financial Officer
(Principal financial officer)
/s/ Catherine A. Brooks
Vice President and Controller
Catherine A. Brooks
(Principal accounting officer)
 
 
 
 
 
 
 
 
 
 
 
 
198
/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/ William H. McRaven
Director
William H. McRaven
/s/ Sharmila Mulligan
Director
Sharmila Mulligan
/s/ Arjun N. Murti
Director
Arjun N. Murti
/s/ Robert A. Niblock
Director
Robert A. Niblock