10-K
CONOCOPHILLIPS (COP)
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
70.
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.”
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
70.
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.
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
76
and is incorporated herein by reference.
Report of Independent Registered Public Accounting
Firm
This report is included in Item 8 on page
80
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
75
, 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
188
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
Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
2.2†‡
Purchase and Sale Agreement, dated March 29, 2017, by and among ConocoPhillips Company,
ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy Partnership,
ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership,
ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by reference to
Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed
by ConocoPhillips on May 4, 2017).
2.3†‡
Asset Purchase and Sale Agreement Amending Agreement, dated as of May 16, 2017, by and
among ConocoPhillips Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada
Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC)
Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by
reference to Exhibit 2.2 to the Current Report of ConocoPhillips on Form 8-K filed on May 18,
3.1
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008;
3.2
Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips
(incorporated by reference to Exhibit 3.2 to the Current Report of ConocoPhillips on Form 8-K filed
on August 30, 2002; File No. 000-49987).
3.3
Amended and Restated By-Laws of ConocoPhillips, as amended and restated as of October 9, 2015
(incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed
on October 13, 2015; File No. 001-32395).
ConocoPhillips and its subsidiaries are parties
to several debt instruments under which the total
amount of securities authorized does not exceed
10 percent of the total assets of ConocoPhillips
and
its subsidiaries on a consolidated basis.
Pursuant to paragraph 4(iii)(A) of Item 601(b)
of
Regulation S-K, ConocoPhillips agrees to furnish
a copy of such instruments to the SEC upon
request.
4.1*
Description of Securities of the Registrant.
10.1
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
10.2
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
Exhibit
Number
Description
189
10.3
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.4
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended
December 31, 1999; File No. 001-00720).
10.5
Amendment and Restatement of ConocoPhillips Supplemental Executive Retirement Plan, dated
http://www.sec.gov/Archives/edgar/data/1163165/000119312512325680/d358543dex1014.htm
(incorporated by reference to Exhibit 10.14 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.6
Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference
to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.7
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
10.8
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
10.9
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to
Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.10.1*
Amended and Restated ConocoPhillips Key Employee Supplemental Retirement Plan, dated
10.10.2
Eighth Amendment to Retirement Plans as amended and restated effective January 1, 2016
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended June 30, 2018; File No. 001-32395).
10.11.1*
Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title I, dated
10.11.2*
Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title II, dated
10.12
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
10.13
Amendment and Restatement of 1998 Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2002; File No. 000-49987).
10.14
Amendment and Restatement of 1998 Key Employee Stock Performance Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2002; File No. 000-49987).
Exhibit
Number
Description
190
10.15
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
10.16.1
Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of the
Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended
December 31, 1999; File No. 001-14521).
10.16.2
Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.16.3
Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998 (incorporated by
reference to Exhibit 10.17.3 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2015; File No. 001-32395).
10.16.4
First Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated May 3, 1999 (incorporated by reference to Exhibit 10.17.4 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.5
Second Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated January 15, 2002 (incorporated by reference to Exhibit 10.17.5 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
10.16.6
Third Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated October 5, 2006 (incorporated by reference to Exhibit 10.17.6 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
10.16.7
Fourth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 1, 2012 (incorporated by reference to Exhibit 10.17.7 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.8
Fifth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 20, 2015 (incorporated by reference to Exhibit 10.17.8 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.17.1
ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003;
10.17.2
First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program
(incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarterly period ended June 30, 2008; File No. 001-32395).
10.18
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2003; File No. 000-49987).
10.19.1*
Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title I,
dated January 1, 2020 (incorporated by reference to Exhibit 10.12.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
Exhibit
Number
Description
191
10.19.2*
Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title II,
dated January 1, 2020 (incorporated by reference to Exhibit 10.12.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.20
Amendment and Restatement of ConocoPhillips Key Employee Change in Control Severance Plan,
effective January 1, 2014 (incorporated by reference to Exhibit 10.21 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2013; File No. 001-32395).
10.21
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-
10.22.1
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual
Meeting of Shareholders; File No. 000-49987).
10.22.2
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2008; File No. 001-32395).
10.22.3
Form of Performance Share Unit Award Agreement under the Performance Share Program under
the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2008; File No. 001-32395).
10.23
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7,
2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2007; File No. 001-32395).
10.24
2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2009 Annual
Meeting of Shareholders; File No. 001-32395).
10.25.1
2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2011 Annual
Meeting of Shareholders; File No. 001-32395).
10.25.2
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
effective February 9, 2012 (incorporated by reference to Exhibit 10 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2012; File No. 001-32395).
10.25.3
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated September 18, 2012
(incorporated by reference to Exhibit 10.26.5 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.4
Form of Performance Share Unit Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.6 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
Exhibit
Number
Description
192
10.25.5
Form of Performance Share Unit Agreement—Canada under the Restricted Stock Program under
the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.7 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.6
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.8 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.7
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 5, 2013 (incorporated by reference to Exhibit 10.26.9 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2012; File No. 001-32395).
10.25.8
Form of Make-Up Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated January 1, 2012 (incorporated by reference to Exhibit 10.1
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2013;
10.25.9
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 18, 2014 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
10.25.10
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.12 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.25.11
Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.25.12
Form of Performance Period IX Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.3 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-
10.25.13
Form of Performance Period IX Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.4 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
10.25.14
Form of Performance Period X Award Agreement, as part of the ConocoPhillips Performance Share
Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 18, 2014 (incorporated by reference to Exhibit 10.5 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
Exhibit
Number
Description
193
10.25.15
Form of Performance Period XIV Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.23 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
10.25.16
Form of Performance Period XIV Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.24 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
10.25.17
Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated March 31, 2014 (incorporated by reference to Exhibit 10.11
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File
10.25.18
Form of Performance Share Unit Award Terms and Conditions for Performance Period 18, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 13, 2018 (incorporated by reference
to Exhibit 10.26.24 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2017; File No. 001-32395).
10.25.19
Form of Performance Share Unit Award Terms and Conditions for Performance Period 18 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 13, 2018 (incorporated by reference to Exhibit 10.26.25 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No. 001-32395).
10.26.1
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K filed on May 14, 2014; File
10.26.2
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated September 3, 2015 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
10.26.3
Form of Retention Award Terms and Conditions, as part of the Restricted Stock Unit Award,
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended March 31, 2015; File No. 001-32395).
10.26.4
Form of Non-Employee Director Restricted Stock Units Terms and Conditions, as part of the
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips, dated January 15,
2016 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of ConocoPhillips on Form
10-Q for the quarter ended March 31, 2016; File No. 001-32395).
10.26.5
Form of Non-Employee Director Restricted Stock Units Terms and Conditions – Canadian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.4 to the Quarterly
Exhibit
Number
Description
194
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-
10.26.6
Form of Non-Employee Director Restricted Stock Units Terms and Conditions – Norwegian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.5 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-
10.26.7
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Stock Option
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 14, 2017 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.8
Form of Performance Share Unit Award Terms and Conditions for Performance Period 17, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 14, 2017 (incorporated by reference
to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended
March 31, 2017; File No. 001-32395).
10.26.9
Form of Performance Share Unit Award Terms and Conditions for Performance Period 17 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 14, 2017 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.10
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 14, 2017 (incorporated by reference to Exhibit 10.4 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.11
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Executive
Restricted Stock Unit Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 13, 2018 (incorporated by reference to Exhibit 10.27.12 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No.
10.26.12
Form of Key Employee Award Terms and Conditions for eligible employees on the Canada payroll,
as part of the ConocoPhillips Executive Restricted Stock Unit Program granted under the 2014
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 13, 2018
(incorporated by reference to Exhibit 10.27.13 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 001-32395).
10.26.13
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 13, 2018 (incorporated by reference to Exhibit 10.27.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No. 001-32395).
10.26.14
Form of Retention Award Terms and Conditions, 2017 revision, as part of the Restricted Stock Unit
Award, granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.27.15 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 001-32395).
Exhibit
Number
Description
195
10.26.15
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Unit Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 14, 2019.
10.27*
Amended and Restated 409A Annex to Nonqualified Deferred Compensation Arrangements of
ConocoPhillips, dated January 1, 2020 (incorporated by reference to Exhibit 10.8 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.28
Amendment, Change of Sponsorship, and Restatement of Certain Nonqualified Deferred
Compensation Plans of ConocoPhillips, dated April 19, 2012 (incorporated by reference to Exhibit
10.10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012;
10.29
Amendment and Restatement of the Burlington Resources Inc. Management Supplemental Benefits
Plan, dated April 19, 2012 (incorporated by reference to Exhibit 10.9 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.30
Amendment and Restatement of Deferred Compensation Trust Agreement for Non-Employee
Directors of Phillips Petroleum Company, dated June 23, 1995 (incorporated by reference to Exhibit
10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016;
10.31
Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
10.32
Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66,
dated April 26, 2012 (incorporated by reference to Exhibit 10.2 to the Current Report of
ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).
10.33
Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated
by reference to Exhibit 10.3 to the Current Report of ConocoPhillips on Form 8-K filed on May 1,
10.34
Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 12, 2012
(incorporated by reference to Exhibit 10.4 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.35
Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012
(incorporated by reference to Exhibit 10.5 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.36
ConocoPhillips Clawback Policy dated October 3, 2012 (incorporated by reference to Exhibit 10.3
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012;
10.37
Term Loan Agreement, between ConocoPhillips, as borrower, ConocoPhillips Company, as
guarantor, Toronto Dominion (Texas) LLC, as administrative agent and the banks party thereto,
with TD Securities (USA) LLC, as lead arranger and bookrunner, dated March 18, 2016
(incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K
filed on March 21, 2016; File No. 001-32395).
Exhibit
Number
Description
196
10.38
Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated December 28, 2018
(incorporated by reference to Exhibit 10.39 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2019; File No. 001-32395).
10.40
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated September 23, 2019 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
21*
List of Subsidiaries of ConocoPhillips.
23.1*
23.2*
Consent of DeGolyer and MacNaughton.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange
32*
Certifications pursuant to 18 U.S.C. Section 1350.
99*
Report of DeGolyer and MacNaughton.
101.INS*
Inline XBRL Instance Document.
101.SCH*
Inline XBRL Schema Document.
101.CAL*
Inline XBRL Calculation Linkbase Document.
101.DEF*
Inline XBRL Definition Linkbase Document.
101.LAB*
Inline XBRL Labels Linkbase Document.
101.PRE*
Inline XBRL Presentation Linkbase Document.
104*
Cover Page Interactive Data File (formatted as Inline XBRL
and contained in Exhibit 101).
*
Filed herewith.
†
The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K.
ConocoPhillips agrees to
furnish a copy of any schedule omitted from this exhibit to the SEC upon request.
‡
ConocoPhillips has previously been granted confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2
under the Securities Exchange Act of 1934, as amended.
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
EX-4.1
Exhibit 4.1
1
DESCRIPTION OF THE REGISTRANT’S
SECURITIES
REGISTERED PURSUANT TO SECTION 12 OF
THE
SECURITIES EXCHANGE ACT OF 1934
As of December 31, 2019, ConocoPhillips
had two classes of securities registered under
Section
12 of the Securities Exchange Act of 1934, as
amended:
our common stock and the 7% Debentures
due 2029 issued by ConocoPhillips Company, as successor to Phillips Petroleum
Company (the “2029
Debentures”). Unless the context otherwise requires,
references to “ConocoPhillips,” “us,” “we”
and
“our” are solely to ConocoPhillips and not to any of
its subsidiaries or affiliates, and references to
“CPCo” refer solely to ConocoPhillips Company, and not any of its subsidiaries
or affiliates.
DESCRIPTION OF CAPITAL STOCK
The following summary description of our common
stock is based upon our certificate of
incorporation and bylaws and applicable provisions
of the law.
The summary is not complete and is
subject to and qualified in its entirety by reference
to the complete text of our certificate
of
incorporation and bylaws, which are filed as
exhibits to this Annual Report on Form
10-K. You
should read those documents for provisions
that may be important to you.
Authorized Capital Stock
We are authorized to issue 2.5 billion shares of common stock, par value $0.01
per share, and
500 million shares of preferred stock, par value
$0.01 per share.
As of December 31, 2019, there were
1,084,868,389 shares of common stock issued and
outstanding and no shares of preferred stock
issued
and outstanding.
Common Stock
Each holder of our common stock is entitled
to one vote per share in the election of directors
and
on all other matters submitted to the vote of
our stockholders. However, except as otherwise required
by law, holders of our common stock are not entitled to vote on any amendment
to our certificate of
incorporation that relates solely to the terms of
any series of our preferred stock if holders
of our
preferred stock are entitled to vote on the amendment
under our certificate of incorporation or
Delaware law. There are no cumulative voting rights, meaning that the holders
of a majority of the
shares of our common stock voting for the election
of directors can elect all of the directors
standing
for election.
Subject to the rights of the holders of any
series of our preferred stock that may be
outstanding
from time to time, each share of our common stock
will have an equal and ratable right to receive
dividends as may be declared by the our board of
directors out of funds legally available for
the
payment of dividends, and, in the event of
our liquidation, dissolution or winding up,
will be entitled
to share equally and ratably in the assets available
for distribution to our stockholders. No holder
of
our common stock will have any preemptive
or other subscription rights to purchase or subscribe
for
any of our securities. In addition, holders of our
common stock have no conversion rights,
and there
are no redemption or sinking fund provisions applicable
to our common stock.
Our common stock is traded on the New York Stock Exchange under the trading
symbol "COP."
The transfer agent for our common stock is
Computershare Shareowner Services LLC.
Exhibit 4.1
2
Anti-Takeover Provisions of ConocoPhillips' Certificate of Incorporation and Bylaws
Our certificate of incorporation and bylaws contain
provisions that could delay or make more
difficult the acquisition of control of us through a hostile
tender offer, open market purchases, proxy
contest, merger or other takeover attempt that a stockholder
might consider in his or her best interest,
including those attempts that might result in
a premium over the market price of our common
stock.
Authorized but Unissued Stock
We have 2.5 billion authorized shares of common stock and 500 million authorized
shares of
preferred stock. One of the consequences of our
authorized but unissued common stock and
undesignated preferred stock may be to enable our
board of directors to make more difficult or to
discourage an attempt to obtain control of us.
If, in the exercise of its fiduciary obligations,
our board
of directors determined that a takeover proposal
was not in our best interest, our board of directors
could authorize the issuance of those shares
without stockholder approval, subject to limits
imposed
by the New York Stock Exchange. The shares could be issued in one or more transactions
that might
prevent or make the completion of a proposed change
of control transaction more difficult or costly
by:
•
diluting the voting or other rights of the proposed
acquiror or insurgent stockholder
group;
•
creating a substantial voting block in institutional
or other hands that might undertake to
support the position of the incumbent board; or
•
effecting an acquisition that might complicate or preclude
the takeover.
In this regard, our certificate of incorporation
grants our board of directors broad power to
establish the rights and preferences of the authorized
and unissued preferred stock. Our board
of
directors could establish one or more series of preferred
stock that entitle holders to:
•
vote separately as a class on any proposed merger or consolidation;
•
cast a proportionately larger vote together with our common
stock on any transaction or
for all purposes;
•
elect directors having terms of office or voting rights
greater than those of other directors;
•
convert preferred stock into a greater number
of shares of our common stock or other
securities;
•
demand redemption at a specified price under prescribed
circumstances related to a
change of control of us; or
•
exercise other rights designed to impede a takeover.
Stockholder Action by Written Consent; Special Meetings of Stockholders
Our certificate of incorporation provides that
no action that is required or permitted to be taken
by
stockholders at any annual or special meeting
may be taken by written consent of stockholders in
lieu
of a meeting, and that special meetings of stockholders
may be called only by our board of directors
or
the chairman of the board.
Advance Notice Procedure for Director
Nominations and Stockholder Proposals; Proxy
Access
Our bylaws provide the manner in which stockholders
may give notice of stockholder nominations
and other business to be brought before an annual
meeting. In general, to bring a matter before an
annual meeting or to nominate a candidate for director, a stockholder
must give notice of the proposed
matter or nomination not less than 90 and not more
than 120 days prior to the first anniversary date of
the immediately preceding meeting. If the annual
meeting is not within 30 days before or after
the
Exhibit 4.1
3
anniversary date of the preceding annual meeting,
the stockholder notice must be received not
earlier
than the 120th day prior to the date of such annual
meeting and not later than the close of business
on
the later of (1) 90 days prior to the date of the
annual meeting or (2) if the first public
announcement
of the date of such annual meeting is less
than 100 days prior to the date of the annual
meeting, the
close of business on the 10th day following the day
on which notice of the annual meeting was mailed
or first publicly disclosed.
In addition to the director nomination provisions
described above, our bylaws contain
a “proxy
access” provision that provides that any stockholder
or group of up to twenty stockholders who have
owned 3% or more of our outstanding common stock
continuously for at least three years to nominate
and include in our proxy materials director
candidates constituting up to 20% of our board
of directors
or two directors, whichever is greater, provided that the stockholders
and the nominees satisfy the
eligibility requirements specified in our bylaws.
A stockholder proposing to nominate a person for
election to our board of directors through the proxy
access provision must provide us
with a notice
requesting the inclusion of the director nominee in
our proxy materials and other required information
not less than 120 days nor more than 150 days
prior to the first anniversary of the date on
which we
first mail our proxy materials for the preceding
year's annual meeting of stockholders.
In addition, an
eligible stockholder may include a written statement
of not more than 500 words supporting
the
candidacy of such stockholder nominee. The complete
proxy access provision for director
nominations are set forth in our bylaws.
These procedures may limit the ability of stockholders
to nominate candidates for director and
bring other business before a stockholders meeting,
including the consideration of any transaction
that
could result in a change of control and that might
result in a premium to our stockholders.
Fair Price Provision
Our certificate of incorporation requires that specified
business combinations involving a person
or entity that beneficially owns 15% or more of
the outstanding shares of our voting stock
or that is an
affiliate of that person, which we refer to as a related person,
must be approved by (1) at least 80% of
the votes entitled to be cast by the voting stock
and (2) at least 66
2
/3% of the votes entitled to be cast
by the voting stock other than voting stock owned
by the related person. These supermajority
requirements do not apply if:
•
a majority of the directors who are unaffiliated with the
related person and who were in
office before the related person became a related person
approve the transaction; or
•
specified fair price conditions are met that
in general provide that the payment received
by the stockholders in the business combination
is not less than the amount the related
person paid or agreed to pay for any shares of our
voting stock acquired within one year
of the business combination.
Amendment of Certificate of Incorporation
and Bylaws
Amendments to our certificate of incorporation
generally must be approved by our board of
directors and by a majority of the outstanding
stock entitled to vote on the amendment,
and, if
applicable, by majority of the outstanding stock
of each class or series entitled to vote on the
amendment as a class or series.
Under our certificate of incorporation, the affirmative
vote of shares representing not less than
80% of the votes entitled to be cast by the voting
stock is required to alter, amend or adopt any
provision inconsistent with or repeal the provisions
that, among others, (1) control the constitution
of
our board of directors, (2) deny stockholders the
right to call a special meeting or to act
by written
Exhibit 4.1
4
consent, (3) limit or eliminate the liability
of our directors and (4) set the 80% supermajority
threshold
applicable with respect to the provisions above.
Additionally, the affirmative vote of shares representing (1) not less than 80% of the
votes
entitled to be cast by the voting stock, voting together
as a single class, and (2) not less than 66
2
/3% of
the votes entitled to be cast by the voting stock
not owned, directly or indirectly, by any related person
is required to amend, repeal, or adopt any provisions
inconsistent with, the fair price provision
described above.
Our bylaws have similar supermajority vote requirements
for provisions relating to, among
others, special stockholder meetings; prohibition
on action by stockholder written consent;
nominating
directors and bringing business before an annual
stockholder meeting; the number, classification and
qualification of directors; filling vacancies
on the board of directors; and removing directors.
Limitation of Liability of Directors
To the fullest extent permitted by Delaware law, our directors will not be personally liable to us
or our stockholders for monetary damages for breach
of fiduciary duty as a director. Delaware law
currently permits the elimination of all liability
for breach of fiduciary duty, except liability:
•
for any breach of the duty of loyalty to us or our
stockholders;
•
for acts or omissions not in good faith or involving
intentional misconduct or a knowing
violation of law;
•
for unlawful payment of a dividend or unlawful stock
purchases or redemptions; and
•
for any transaction from which the director derived
an improper personal benefit.
As a result, neither us nor our stockholders
have the right, through stockholders' derivative
suits
on our behalf, to recover monetary damages
against a director for breach of fiduciary
duty as a
director, including breaches resulting from grossly negligent behavior, except in the situations
described above.
Delaware Anti-Takeover Law
We are a Delaware corporation and is subject to Section 203 of the Delaware General
Corporation Law, which regulates corporate acquisitions. Section 203 prevents
an “interested
stockholder,” which is defined generally as a person owning 15% or
more of a corporation's voting
stock, or any affiliate or associate of that person, from engaging
in a broad range of “business
combinations” with the corporation for three years
after becoming an interested stockholder
unless:
•
the board of directors of the corporation had
previously approved either the business
combination or the transaction that resulted in
the stockholder's becoming an interested
stockholder;
•
upon completion of the transaction that resulted
in the stockholder's becoming an
interested stockholder, that person owned at least 85% of the voting
stock of the
corporation outstanding at the time the transaction
commenced, excluding shares owned
by persons who are directors and also officers and shares
owned in employee stock plans
in which participants do not have the right to determine
confidentially whether shares
held subject to the plan will be tendered in a tender
or exchange offer; or
•
following the transaction in which that person became
an interested stockholder, the
business combination is approved by the board of
directors of the corporation and holders
of at least two-thirds of the outstanding voting stock
not owned by the interested
stockholder.
Exhibit 4.1
5
Under Section 203, the restrictions described
above also do not apply to specific business
combinations proposed by an interested stockholder
following the announcement or notification
of
designated extraordinary transactions involving the corporation
and a person who had not been an
interested stockholder during the previous three
years or who became an interested stockholder
with
the approval of a majority of the corporation's
directors, if such extraordinary transaction is
approved
or not opposed by a majority of the directors who
were directors prior to any person becoming an
interested stockholder during the previous three
years or were recommended for election or elected
to
succeed such directors by a majority of such
directors.
Section 203 may make it more difficult for a person
who would be an interested stockholder to
effect various business combinations with a corporation
for a three-year period.
DESCRIPTION OF THE 2029 DEBENTURES
The following description of the 2029 Debentures
is a summary and does not purport to
be
complete.
It is subject to and qualified in its entirety
by reference to the Indenture, dated September
15, 1990 (the “Indenture”), as supplemented by
Supplemental Indenture No. 1, dated May
23, 1991,
and the Supplement, dated September 9, 2002 (together
with the Indenture, the “Senior Indenture”),
between CPCo (as successor to Phillips Petroleum
Company) and U.S. Bank National Association,
formerly First Trust National Association (as successor to
Continental Bank, National Association), as
trustee, forms of which are available from us
upon request.
The 2029 Debentures are traded on the
NYSE Stock Exchange under CUSIP No. 718507BK1.
You
should read the Senior Indenture for
provisions that may be important to you.
Interest and Maturity
The 2029 Debentures were initially issued
in aggregate principal amount of $200,000,000
and bear
interest at the rate of 7% per year. The maturity date of the 2029 Debentures
is March 30, 2029.
Interest on the 2029 Debentures are payable semiannually
on March 30 and September 30 of each
year, commencing September 30, 1999, to the holders of record
of the 2029 Debentures at the close of
business on the preceding March 15 or September
15, whether or not that day is a business day. All
payments of interest and principal are payable in
United States dollars.
Principal and interest on the 2029 Debentures are
payable, and the 2029 Debentures may
be presented
for transfer and exchange, at the corporate trust
office or agency of the trustee in New York, New
York or Chicago, Illinois.
Payment of interest may also be made by check
mailed to the registered
holders, at our option.
Ranking; Guarantees
The 2029 Debentures are senior unsecured obligations
of CPCo and rank equally in right of payment
to all of CPCo’s other unsecured senior indebtedness. The 2029 Debentures
are not be entitled to the
benefit of any sinking fund. ConocoPhillips
has fully and unconditionally guaranteed, on a senior
unsecured basis, the full and prompt payment of the
principal of and interest on the 2029 Debentures,
when and as they be become due and payable,
whether at maturity or otherwise.
Optional Redemption
At CPCo’s option, CPCo may redeem the 2029 Debentures, in whole
or in part, at any time or from
time to time at a redemption price equal to the greater
of (i) 100 percent of the principal amount of the
2029 Debentures to be redeemed, and (ii) the sum
of the present values of the remaining scheduled
payment of principal and interest on the 2029
Debentures to be redeemed (not including any portion
of such payments of interest accrued as of the date
of redemption) discounted to the date
of
Exhibit 4.1
6
redemption on a semi-annual basis (assuming
a 360-day year consisting of twelve 30-day
months) at
the Adjusted Treasury Rate (as defined below) plus 25 basis
points for the 2029 Debentures, as
determined by the Quotation Agent (as defined below),
in each case, plus accrued interest thereon
to
the date of redemption.
Notice of any redemption must be mailed at least
30 days but not more than 60 days before
the
redemption date to each holder of the 2029
Debentures to be redeemed. Unless CPCo defaults
in
payment of the redemption price, on and after
the redemption date, interest will cease to accrue on
the
2029 Debentures or portions thereof called for
redemption.
“Adjusted Treasury Rate” means, with respect to any redemption
date, the rate per annum equal to the
semi-annual equivalent yield to maturity of
the Comparable Treasury Issue, assuming a price for the
Comparable Treasury Issue (expressed as a percentage of
its principal amount) equal to the
Comparable Treasury Price for such redemption date.
“Comparable Treasury Issue” means the United States Treasury security selected
by the Quotation
Agent as having a maturity comparable to the
remaining term of the 2029 Debentures to
be redeemed
that would be utilized, at the time of selection
and in accordance with customary financial practice,
in
pricing new issues of corporate debt securities of
comparable maturity to the remaining term
of the
2029 Debentures.
“Comparable Treasury Price” means, with respect to any
redemption date, (i) the average of the
Reference Treasury-Dealer Quotations for such redemption date,
after excluding the highest and
lowest of
such Reference Treasury Dealer Quotations, or (ii) if the trustee
obtains fewer than three such
Reference
Treasury Dealer Quotations, the average of all such quotations.
“Quotation Agent” means the Reference Treasury Dealer appointed
by CPCo.
“Reference Treasury Dealer” means (i) each of Merrill
Lynch, Pierce, Fenner & Smith Incorporated,
Chase Securities Inc., Goldman, Sachs & Co.
and J.P.
Morgan Securities Inc. and their respective
successors;
provided, however, that if any of the foregoing shall cease to be a primary
U.S. Government securities
dealer
in New York City (a "Primary Treasury Dealer"), CPCo shall substitute therefor another Primary
Treasury
Dealer, and (ii) any other Primary Treasury Dealer selected by CPCo.
“Reference Treasury Dealer Quotations” means, with respect
to each Reference Treasury Dealer and
any
redemption date, the average, as determined by
CPCo, of the bid and asked prices for the Comparable
Treasury Issue (expressed in each case as a percentage of its
principal amount) quoted in writing to the
trustee by such Reference Treasury Dealer at 5:00 p.m., New
York City time, on the third business
day preceding such
redemption date.
Certain Covenants
Limitation on Liens
CPCo will not, and will not permit any Restricted
Subsidiary (as defined below) to, incur, issue,
assume or guarantee any indebtedness for borrowed
money secured by a mortgage, pledge or other
lien (“Mortgage”) on any Restricted Property
(as defined below), or on any shares of stock or
Exhibit 4.1
7
indebtedness of a Restricted Subsidiary, without providing that the 2029 Debentures
shall be secured
equally and ratably with (or prior to) such secured
indebtedness, unless after giving effect thereto
the
aggregate amount of all such indebtedness so
secured (other than indebtedness secured by excepted
Mortgages referred to in the following sentence),
together with all CPCo’s Attributable Debt (as
defined below) and CPCo’s Restricted Subsidiaries in respect of sale and leaseback
transactions
involving Restricted Property, except sale and leaseback transactions, the proceeds
of which are
applied to the retirement of funded debt, would not
exceed 10 percent of Consolidated Adjusted
Net
Assets (as defined below) as shown on CPCo’s latest audited consolidated
financial statements. This
restriction will not apply to (a) Mortgages on property
of, or on any shares of stock or indebtedness
of,
any corporation existing at the time such corporation
becomes a Subsidiary (as defined below), (b)
Mortgages on property existing at the time
of acquisition thereof (including acquisition
through
merger or consolidation) or to secure the payment of all
or any part of the purchase price or
construction cost thereof or to secure any indebtedness
incurred prior to, at the time of, or within six
months after such acquisition or completion of such
property for the purpose of financing
all or any
part of the purchase price or construction cost thereof,
(c) Mortgages on substantially unimproved
property to secure the cost of exploration, drilling
or development of, or improvements to, such
property, and (d) Mortgages in favor of CPCo or a Restricted Subsidiary, and will not apply to any
extension, renewal or replacement of any
Mortgage referred to in the foregoing clauses
(a) through
(d), inclusive. The following types of transactions
are not deemed to create indebtedness
secured by
Mortgage (a) the sale or transfer of crude oil, natural
gas or natural gas liquids in place for a period
of
time until, or in an amount such that, the purchaser
will realize there from a specified amount of
money or of such oil, gas or gas liquids, or any
other interest in property commonly referred
to as a
"production payment,” and (b) the Mortgage
of any property of CPCo or any Subsidiary
in favor of
governmental bodies to secure partial progress,
advance or other payments to CPCo or
any Subsidiary
pursuant to any contract or statute, or the Mortgage
of any property to secure indebtedness of the
pollution control or industrial revenue bond type.
Limitation on Sales and Leasebacks
Neither CPCo nor any Restricted Subsidiary may
enter into any sale and leaseback transaction
involving any Restricted Property which has been
owned or operated by CPCo or such
Restricted
Subsidiary for more than six months unless (a)
CPCo or such Restricted Subsidiary could
mortgage
such property in an amount equal to the
Attributable Debt with respect to the sale and leaseback
transaction without equally and ratably securing
the 2029 Debentures, (b) since the date
of the Senior
Indenture and within a period commencing
12 months prior to the consummation of the
sale and
leaseback transaction and ending 12 months after
the consummation of such sale and leaseback
transaction, CPCo or any Restricted Subsidiary
has expended or will expend for any Restricted
Property an amount equal to (i) the greater
of (x) the net proceeds of such sale and leaseback
transaction and (y) the fair market value of the
Restricted Property so leased at the time
of entering
into such transaction, as determined by CPCo’s board of directors
(the greater of the sums specified in
clauses (x) and (y) being referred to herein as the
"Net Proceeds of such transaction"), and CPCo
elects to designate such amount as satisfying
any obligation it would otherwise have under
clause (c)
hereof, or (ii) a part of the Net Proceeds of such
transaction and CPCo elects to designate
such amount
as satisfying part of the obligation it would otherwise
have under clause (c) hereof and applies
an
amount equal to the remainder of such Net Proceeds
as provided in clause (c) hereof, or (c) CPCo,
within 12 months of the consummation of any
such sale and leaseback transaction, applies
an amount
equal to the Net Proceeds of such transaction (less
any amount elected under clause (b) hereof)
to the
retirement of certain funded indebtedness of CPCo
ranking on a parity with the 2029 Debentures.
This
restriction will not apply to certain sale and leaseback
transactions (a) between CPCo and a Restricted
Subsidiary or between Restricted Subsidiaries,
or (b) involving the taking back of a lease
for a period
of less than three years.
Exhibit 4.1
8
Limitations on Mergers and Sales of Assets
Neither the Senior Indenture nor the 2029 Debentures
contain covenants or other provisions to afford
protection to the holders of the 2029 Debentures in
the event of a recapitalization, holding
company
merger, or other transaction (leverage or otherwise) with CPCo, CPCo’s management or affiliates,
except to the limited extent described below.
CPCo may not consolidate with, or merge into, any corporation
or convey or transfer its properties
and assets substantially as an entirety to any person
unless the successor entity shall be a corporation
organized under the laws of the United States or any
state or the District of Columbia and shall
expressly assume CPCo’s obligations under the Senior Indenture. If, upon
any such consolidation,
merger, conveyance or transfer of CPCo with or into any person or of any
Restricted Subsidiary with
or to any other Subsidiary, any Restricted Property of CPCo or of any Restricted
Subsidiary or any
shares of stock or indebtedness of any Restricted
Subsidiary would thereupon become subject
to any
Mortgage (other than a Mortgage permitted under
the limitation on liens described above, without
CPCo having to secure the 2029 Debentures equally
and ratably), CPCo will secure the 2029
Debentures (together with, if CPCo shall so
determine, other securities ranking on a parity
with the
2029 Debentures) prior to all liens other than any
theretofore existing.
Definitions
“Attributable Debt” is defined to mean the total
net amount of rent (discounted at the rate
per annum
indicated in the Senior Indenture) required to
be paid during the remaining term of any
lease.
“Consolidated Adjusted Net Assets” is defined to mean
the total amount of assets after deducting
therefrom (a) all current liabilities (excluding
any thereof which are by their terms extendible
or
renewable at the option of the obligor thereon to
a time more than twelve months after the time
as of
which the amount thereof is being computed), and
(b) total prepaid expenses and deferred charges.
“Restricted Property” is defined to mean (a) any interest
in property located in the United States
(including any interest in property located off the coast
of the United States operated pursuant
to
leases from any governmental body) which is producing
crude oil, natural gas or natural gas liquids in
paying quantitates, or (b) any refining or manufacturing
plant located in the United States, except (i)
related transportation or marketing facilities,
or (ii) any refining or manufacturing plant or portion
thereof which, in the opinion of CPCo’s board of directors, is not a principal
plant in relation to
CPCo’s activities and Restricted Subsidiaries as a whole.
“Restricted Subsidiary” is defined to mean any
Subsidiary which owns a Restricted Property
if
substantially all of the tangible property in
which such Subsidiary has an interest in (a) is
located in
the United States, or (b) is located off the coast of the United
States and is operated pursuant to leases
from any governmental body.
“Subsidiary” is defined to mean a corporation,
a majority of the outstanding voting stock
of which is
owned, directly or indirectly, by CPCo or by one or more other Subsidiaries,
or by CPCo and one or
more other Subsidiaries.
Exhibit 4.1
9
Modifications of the Senior Indenture
The Senior Indenture contains provisions permitting
CPCo and the trustee, with the consent of
the
holders of not less than 66⅔ percent-in principal
amount of the 2029 Debentures at the time
outstanding, to modify the Senior Indenture or
any supplemental indenture, or the rights
of the holders
of the 2029 Debentures; provided that no such modification
shall (i) extend the fixed maturity of the
2029 Debentures, or reduce the principal amount
thereof (including in the case of a discounted
security the amount payable thereon in the event
of acceleration or the amount provable in
bankruptcy) or any redemption premium thereon,
or reduce the rate or extend the time of payment of
interest thereon, or make the principal of, or interest
or premium on, the 2029 Debentures payable
in
any coin or currency other than that provided in
the 2029 Debentures, or impair or affect the right
of
any 2029 Debentures holder to institute
suit for the payment thereof or the right of prepayment,
if any,
at the option of the holder, without the consent of the holder
of each 2029 Debentures so affected, or
(ii) reduce the aforesaid percentage of 2029 Debentures
the consent of the holders of which is required
for any such modification.
Events of Default
An Event of Default is defined in the Senior Indenture
as being:
●
Default for 30 days in payment of any interest
on the 2029 Debentures;
●
Default in payment of principal and premium of
the 2029 Debentures as and when the
same
shall become due and payable either at maturity, upon redemption, by declaration
or
otherwise;
●
Default by CPCo in the performance of any other
of the covenants or agreements in the
Senior Indenture which shall not have been remedied
for a period of 90 days after notice; or
●
Certain events of bankruptcy, insolvency, and reorganization of CPCo.
The Senior Indenture provides that the trustee
may withhold notice to the holders of the 2029
Debentures of any default (except in payment
of principal or of interest or premium on the 2029
Debentures) if the trustee considers it in
the interest of the holders to do so.
If an Event of Default due to the default in the
payment of principal, interest or premium,
if any, on
the 2029 Debentures shall have occurred and
be continuing, either the trustee or the holders
of 25
percent in principal amount of the 2029 Debentures
affected thereby then outstanding may declare the
principal of all such 2029 Debentures to be
due and payable immediately. If an Event of Default
resulting from default in performance of any other
of the covenants or agreements in the
Senior
Indenture or certain events of bankruptcy, insolvency and reorganization of CPCo, either
the trustee or
the holders of 25 percent in principal amount of all
2029 Debentures then outstanding may
declare the
principal of all 2029 Debentures to be due and
payable immediately, but upon certain conditions such
declarations may be annulled and past defaults
may be waived (except defaults in payment
of
principal of or interest or premium on the 2029
Debentures) by the holders of a majority in
principal
amount of the 2029 Debentures then outstanding.
The holders of a majority in principal amount
of the 2029 Debentures affected and then outstanding
shall have the right to direct the time, method
and place of conducting any proceeding for any remedy
available to the trustee under the Senior Indenture,
provided that holders of the 2029 Debentures
have
offered to the trustee reasonable indemnity against expenses
and liabilities.
Defeasance
The
Senior
Indenture
provides
that
CPCo,
at
its
option:
(a)
will
be
discharged
from
any
and
all
obligations in respect of the
2029 Debentures (except for certain
obligations to register the transfer
or
Exhibit 4.1
10
exchange
of
2029
Debentures,
replace
stolen,
lost
or
mutilated
2029
Debentures,
maintain
paying
agencies and
hold moneys
for payment
in trust)
or (b)
need not
comply with
certain restrictive
covenants
of the Senior Indenture (including those described herein), in each case if CPCo deposits, in trust with
the trustee or the defeasance agent, money or U.S. government obligations which through the payment
of interest
thereon and
principal thereof
in accordance
with their
terms will
provide money, in
an amount
sufficient to pay all the principal (including
any mandatory sinking fund payments)
of, and interest and
premium, if any,
on, the 2029
Debentures on the
dates such payments are
due in accordance
with the
terms of such 2029 Debentures.
Governing Law
The Senior Indenture and the 2029 Debentures are
governed by the internal law of the State of
New
York.
EX-10.10.1
Exhibit 10.10.1
1
CONOCOPHILLIPS
KEY EMPLOYEE SUPPLEMENTAL RETIREMENT PLAN
2020 AMENDMENT AND RESTATEMENT
The ConocoPhillips
Key Employee
Supplemental Retirement
Plan (“KESRP”)
is hereby
amended
and
restated
effective
as
of
January
1,
2020
(except
where
another
date
is
specified herein with regard to a particular provision).
Immediately
prior
to
effectiveness
of
this
2020
Amendment
and
Restatement,
KESRP
was
and
remains
subject
to
the
2012
Restatement
of
the
Key
Employee
Deferred
Compensation Plan
of ConocoPhillips,
Title
II, which
was effective
as of.
the "Effective
Time"
defined in
the Employee
Matters Agreement
by and
between ConocoPhillips
and
Phillips
66
(the
"Effective
Time")
and
conditioned
on
the
occurrence
of
the
"Distribution"
defined
in
such
Employee
Matters
Agreement
(the
"Distribution"),
together
with
the
First
Amendment
to
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan
(2012
Restatement),
effective
September
1,
2015,
and
the
Second
Amendment
to
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan
(2012
Restatement), effective April 1, 2016.
Preamble
The
purpose
of
the
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan
(the
"Plan")
is
to
attract
and
retain
key
employees
by
providing
them
with
supplemental
retirement benefits.
The Plan
is sponsored
and maintained by
ConocoPhillips Company.
The
Plan
is
intended
to
be
and
shall
be
administered
in
part
as
an
unfunded
pension
excess
benefit
plan
within
the
meaning
of
ERISA
Section
3(36)
and
in
part
as
“a
plan
which
is
unfunded
and
is
maintained
by
an
employer
primarily
for
the
purpose
of
providing
deferred
compensation
for
a
select
group
of
management
or
highly
compensated employees” within the meaning of sections
201(2), 301(a)(3), and 401(a)(1)
of
ERISA.
Notwithstanding
any
other
provision
of
this
Plan,
this
Plan
shall
be
interpreted, operated, and administered in a manner consistent with these intentions.
Exhibit 10.10.1
2
PRE-AMERICAN JOBS CREATION
ACT OF 2004
GRANDFATHERED
PROVISIONS
Benefits
under
this
Plan,
formerly
called
the
Key
Employee
Supplemental
Retirement
Plan
of
Phillips
Petroleum
Company
(the
“Phillips
Plan”),
that
commenced
prior
to
January
1,
2005
(“AJCA-grandfathered
benefits”),
shall
be
subject
exclusively
to
the
terms
and
conditions
of
the
Phillips
Plan
in
effect
on
or
before
October
3,
2004.
No
change
in
the
ConocoPhillips
Retirement
Plan
adopted
subsequent
to
such
date
and
no
change
in
the
Phillips
Plan
or
in
the
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan
adopted
after
such
date
shall
apply
to
an
AJCA-grandfathered
benefit.
Provided,
however,
for
purposes
of
this
paragraph,
benefits
shall
be
deemed
to
have
commenced
prior
to
January
1,
2005,
and
shall
be
AJCA-grandfathered
benefits
if
the
relevant corporate officer
or committee approved
the Employee’s
petition regarding time
and
form
of
payment
before
January
1,
2005,
even
if
the
benefits
commenced
after
December 31,
2004.
The “relevant
corporate officer
or committee”
means the
person or
persons with the authority under the Phillips
Plan to approve a petition regarding the time
and form of payment.
SECTION I. Definitions
Terms used in
this Plan shall have the same meaning they have in the relevant Title
of the
ConocoPhillips Retirement Plan if they are not otherwise specifically defined herein.
As used in this Plan:
(a)
"Beneficiary"
shall
mean
a
person
or
persons
or
the
trustee
of
a
trust
for
the
benefit
of
a
person
designated
by
a
Participant
to
receive,
in
the
event
of
death,
any
unpaid
portion
of
a
Participant's
Benefits
from
this
Plan,
as
provided
in
Section III.
(b)
"Benefit" shall mean an obligation of the Company to pay amounts from the Plan.
(c)
"Board"
shall
mean
the
board
of
directors
of
the
Company,
as
it
may
be
comprised from time to time.
Exhibit 10.10.1
3
(d)
"Code" shall
mean the
Internal Revenue
Code of
1986, as
amended from
time to
time, or any successor statute.
(e)
"Committee" shall
mean the
Nonqualified Plans
Benefit Committee
as appointed
from
time
to
time
by
the
Board;
provided,
however,
that
until
a
successor
is
appointed by
the Board,
the individual
serving as
the Company’s
Vice
President
with responsibility over human resources shall be sole member of the Committee.
(f)
"Company" shall mean
ConocoPhillips Company,
a Delaware corporation,
or any
successor corporation.
The Company is a subsidiary of ConocoPhillips.
(g)
"ConocoPhillips"
shall
mean
ConocoPhillips,
a
Delaware
corporation,
or
any
successor
corporation.
ConocoPhillips
is
a
publicly
held
corporation
and
the
parent of the Company.
(h)
"Controlled
Group" shall mean ConocoPhillips and its Subsidiaries.
(i)
"Employee"
shall
mean
a
person
who
is
an
active
participant
or
a
terminated
vested participant in the Retirement Plan.
(j)
"ERISA"
shall
mean
the
Employee
Retirement
Income
Security
Act
of
1974,
as
amended from time to time, or any successor statute.
(k)
“Final
Average
Earnings”
shall
mean
“final
average
earnings”
as
that
term
is
defined in Title I of the ConocoPhillips Retirement Plan.
(l)
"Incentive
Compensation
Plan"
shall
mean
the
Incentive
Compensation
Plan
of
Phillips Petroleum Company,
the Annual Incentive Compensation Plan of Phillips
Petroleum Company,
the Variable
Cash Incentive Program
of ConocoPhillips,
or
successor plans or programs,
or all, as the context may require.
(m)
"KEDCP"
shall
mean
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips or a successor plan.
(n)
"MSBP"
shall
mean
the
Burlington
Resources
Inc.
Management
Supplemental
Benefits Plan (or any successor plan thereto).
(o)
"Participant"
shall
mean
an
Employee
who
is
eligible
to
receive
a
benefit
from
this
Plan,
whether
as
an
active
participant
who
is
currently
employed
by
a
member
of
the
Controlled
Group
or
as
a
terminated
vested
participant
who
was
previously employed by a member of the Controlled Group.
Exhibit 10.10.1
4
(p)
"Participating
Subsidiary"
shall
mean
a Subsidiary
that
has
adopted
one
or more
plans making Participants eligible for participation in this Plan.
(q)
"Plan"
shall
mean
the
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan,
the
terms
of
which
are
stated
in
and
by
this
document.
The
Plan
is
sponsored and maintained by the Company.
(r)
"Plan Administrator" shall mean the Committee.
(s)
"Plan-age 55"
shall mean
the first
of the
calendar month
after an
Employee’s
age
55
or,
if
earlier,
the
date
the
applicable
title
of
the
Retirement
Plan
treats
the
Employee as being age 55.
(t)
"Plan Year"
shall mean January 1 through December 31.
(u)
"Restricted
Stock"
shall
mean
shares
of
Stock
which
have
certain
restrictions
attached
to
the
ownership
thereof.
It
shall
also
include
restricted
stock
units,
if
applicable,
being
units
each
of
which
shall
represent
a
hypothetical
share
of
Stock,
which
have
certain
restrictions
attached
to
the
ownership
thereof
or
the
delivery of shares pursuant thereto.
(v)
"Retirement
Plan"
shall
mean
the
ConocoPhillips
Retirement
Plan,
which
is
qualified under Code Section 401(a).
(w)
"Salary"
shall
mean
the
monthly
equivalent
rate
of
pay
for
an
Employee
before
adjustments for any before-tax voluntary reductions.
(x)
"Schedule
A
Employee"
shall
mean
an
Employee
whose
name
appears
in
Schedule A attached to and made a part of this Plan.
(y)
"Schedule
B
Employee"
shall
mean
an
Employee
whose
name
appears
in
Schedule B attached to and made a part of this Plan.
(z)
"Schedule
C
Employee"
shall
mean
an
Employee
whose
name
appears
in
Schedule C attached to and made a part of this Plan.
(aa)
"Separation from
Service" shall
mean the
date on
which the
Participant separates
from
service
with
the
Controlled
Group
within
the
meaning
of
Code
section
409A,
whether
by
reason
of
death,
disability,
retirement,
or
otherwise.
In
determining Separation
from Service,
with regard
to a
bona fide
leave of
absence
that is
due to
any medically
determinable physical
or mental
impairment that
can
be expected to result in
death or can be expected
to last for a continuous
period of
Exhibit 10.10.1
5
not
less
than
six
months,
where
such
impairment
causes
the
Employee
to
be
unable
to
perform
the
duties
of
his
or
her
position
of
employment
or
any
substantially similar
position of
employment, a
29-month period
of absence
shall
be
substituted
for
the
six-month
period
set
forth
in
section
1.409A-1(h)(1)(i)
of
the
regulations
issued
under
section
409A
of
the
Code,
as
allowed
thereunder.
For purposes
of this
Plan, Separation
from Service
shall not
include a
separation
caused by death.
(bb)
"Stock" means shares of common stock of ConocoPhillips, par value $.01.
(cc)
"Subsidiary"
shall mean
any corporation
or other
entity that
is treated
as a
single
employer
with
ConocoPhillips
under section
414(b),
(c),
or
(m)
of
the
Code.
In
applying section
1563(a)(1), (2),
and (3)
of the
Code for
purposes of
determining
a
controlled
group
of
corporations
under
section
414(b)
of
the
Code
and
for
purposes of
determining trades
or businesses
(whether or
not incorporated)
under
common
control
under
regulation
section
1.414(c)-2
for
purposes
of
section
414(c) of the Code, the language
“at least 80%” shall
be used without substitution
as allowed under regulations pursuant to section 409A of the Code.
(dd)
"Title
I"
shall
mean
Title
I
of
the
ConocoPhillips
Retirement
Plan
(Phillips
Retirement Income Plan).
(ee)
"Title II"
shall mean Title II of the ConocoPhillips Retirement Plan (Cash Balance
Account).
(ff)
"Title
III"
shall
mean
Title
III
of
the
ConocoPhillips
Retirement
Plan
(Tosco
Pension Plan).
(gg)
"Title IV" shall
mean Title
IV of the ConocoPhillips
Retirement Plan (Retirement
Plan of Conoco).
(hh)
"Total
Final Average
Earnings" shall mean
the sum of:
(i) the average of
the high
3
consecutive
Annual
Earnings,
(including
any
increases
under
Section
II(b)(i)(bb), (ee), (ff)
and (gg) of
this Plan, but
excluding Incentive Compensation
Plan
awards
and
any
increases
under
Section
II(b)(i)(aa),
(cc),
and
(dd)
of
this
Plan), paid or
deemed to be
paid in the
Employee’s
final eleven calendar
years of
employment
with
the
Company
or
a
Participating
Subsidiary
including
the
calendar
year
in
which
the
Employee’s
last
date
of
employment
with
the
Exhibit 10.10.1
6
Company or
a Participating
Subsidiary occurs;
plus (ii)
the average
of the
high 3
Incentive
Compensation
Plan
awards
(including
any
increases
under
Section
II(b)(i)(aa),
(cc),
or
(dd)
of
this
Plan,
but
excluding
any
increases
under
Section
II(b)(i)(bb),
(ee),
(ff)
and
(gg)
of
this
Plan)
paid
or
deemed
to
be
paid
in
the
Employee’s
final
eleven
calendar
years
of
employment
with
the
Company
or
a
Participating Subsidiary including
the calendar year
in which the
Employee’s
last
date
of
employment
with
the
Company
or
Participating
Subsidiary
occurs.
Provided,
however,
in
determining
Total
Final
Average
Earnings,
an
Incentive
Compensation
Plan
award
(and
any
increases
under
the
provisions
of
Section
II(b)(i)
cited
above)
shall
be
taken
into
consideration
only
if
the
Employee
to
whom
such
award
or
increase
applies,
was
at
the
time
of
the
award
or
increase,
classified
in
a
ConocoPhillips
salary
grade
19
or
above
job
or
any
equivalent
salary grade of Phillips Petroleum Company.
(ii)
"Trustee"
shall mean
the trustee
of the
grantor trust
established for
this Plan
by a
trust agreement between the Company and the trustee, or any successor trustee.
SECTION II.
Plan Accrued Benefit.
(a)
An
Employee
shall
be
entitled
to
payments
under
this
Plan
based on
an
accrued
benefit with
the following
components: (i)
his Title
I-related accrued
benefit, (ii)
his
Title
II-related accrued
Benefit,
(iii)
his
Title
III-related
accrued
benefit
(but
only with regard to an Employee who, on or after July
1, 2007, performed an hour
of
service
under
Title
III),
and
(iv)
his
Title
IV-related
accrued
benefit,
each
as
defined below.
An Employee
shall be
entitled to
payments under this
Plan to
the
same extent he is vested in his respective component under the Retirement Plan.
(b)
“Title I-related accrued benefit shall mean the sum of (i), (ii), and (iii) below:
(i)
The difference
between the
Employee’s
total accrued
benefit under Title
I
and
his
actual
accrued
benefit
under
Title
I.
For
this
purpose,
an
Employee’s
“total accrued
benefit under
Title
I” is
the accrued
benefit he
would have if
his accrued
benefit under Title
I were determined
under the
terms of Title I but with the following modifications:
Exhibit 10.10.1
7
(aa)
Include
in
Annual
Earnings
an
award
under
the
Incentive
Compensation
Plan
which
the
employee
deferred
under
the
terms
of the
KEDCP.
Include such
award in
the calendar
year in
which
the award would have been
paid to the Employee
if it had not been
deferred.
(bb)
Include in Annual Earnings salary that would have been paid
to the
Employee
but
for
the
fact
that
he
voluntarily
elected
to
defer
receipt
of
that
salary
under
the
terms
of
KEDCP.
Include
the
deferred
salary
in
Annual
Earnings
in
the
calendar
year
in
which
the salary would have been paid had it not been deferred.
(cc)
Include in Annual Earnings
the initial value
of a restricted stock
or
restricted stock unit award under
the Incentive Compensation Plan.
Include
that
value
in
Annual
Earnings
in
the
calendar
year
in
which the award was granted.
(dd)
Include
in
Annual
Earnings
the
value
of
any
special
award
specified by the Committee under the
terms of the special
award to
be included for
Annual Earnings purposes
under Title
I in the
year
in
which
any
applicable
restrictions
on
the
award
lapse
or,
if
deferred,
in
the
year
in
which
any
applicable
restrictions
would
have lapsed absent an election to defer.
(ee)
Disregard the
limitations on
compensation related
to Code
section
401(a)(17).
(ff)
Disregard the limitation on benefits related to Code section 415.
(gg)
If
an
Employee
is
eligible
to
receive
benefits
under
the
ConocoPhillips
Executive
Severance
Plan
or
under
the
ConocoPhillips Key
Employee Change in
Control Severance
Plan,
include in
Annual Earnings
an amount
determined by
dividing the
Employee’s Salary
by 4.3333 times
the number of weeks
or partial
weeks
from
the
date
the
Employee’s
employment
ends
with
the
Employer to the end of
that calendar year.
Provided, however, this
subsection
(gg)
shall
be
disregarded
to
the
extent
the
benefit
Exhibit 10.10.1
8
created
solely
by
operation
of
this
subsection
(gg)
is
provided
under the terms of Title I.
(hh)
With regard
to a Schedule
B Employee, determine
service credited
for purposes of benefit
accrual as if time
served while on a
Canada
payroll
were
time
served
on
a
United
States
payroll;
provided,
however, that,
if benefit accrual
is at any
time frozen under
Title I,
no further
service shall
be credited
from the
time such
freeze shall
become effective.
(ii)
In
the
case
of
an
Employee
who
terminated
employment
on
or
after
February
8,
1993,
the
Title
I-related
accrued
benefit
shall
include
an
additional
supplemental
accrued
benefit
calculated
under
the
terms
of
Title
I,
but
disregarding
the
limitation
on
compensation
that
is
taken
into
account,
using
as
final
average
earnings
the
difference,
if
any,
between
the
Total
Final
Average
Earnings and the Final Average Earnings used in Title
I.
(ii)
The Title
I-related accrued
benefit shall
also include
any benefit
provided
under Section IV
of this Plan.
(c)
“Title
II-related
accrued
benefit”
shall
mean
the
difference
between
the
Employee’s
total
accrued
benefit
under
Title
II
and
his
actual
accrued
benefit
under Title
II.
For this purpose,
an Employee’s
“total accrued benefit
under Title
II” is the
accrued benefit
he would have
if his accrued
benefit under Title
II were
determined under the terms of Title II but with the following modifications:
(i)
Include
in
Annual
Earnings
an
award
under
the
Incentive
Compensation
Plan
which
the
Employee
deferred
under
the
terms
of
the
KEDCP.
Include
such
award
in
the
calendar
month
and
year
in
which
the
award
would have been paid to the Employee if it had not been deferred.
(ii)
Include
in
Annual
Earnings
salary
that
would
have
been
paid
to
the
employee but for the fact that he voluntarily
elected to defer receipt of that
salary under
the terms
of KEDCP.
Include the
deferred salary
in
Annual
Earnings
in
the
calendar
month
and
year
in
which
the
salary
would
have
been paid had it not been deferred.
Exhibit 10.10.1
9
(iii)
Include
in
Annual
Earnings
the
initial
value
of
a
restricted
stock
or
restricted
stock
unit
award
under
the
Incentive
Compensation
Plan.
Include that
value in
Annual Earnings
in the
calendar month
and
year in
which the award was granted.
(iv)
Include in Annual Earnings the value of any special award specified by the
Committee under the terms
of the special award
to be included for
Annual
Earnings
purposes
under
Title
II
in
the
year
in
which
any
applicable
restrictions
on
the
award
lapse
or,
if
deferred,
in
the
year
in
which
any
applicable restrictions would have lapsed absent an election to defer.
(v)
Disregard
the
limitation
on
compensation
related
to
Code
section
401(a)(17).
(vi)
Disregard the limitation on benefits related to Code section 415.
(d)
“Title
III-related
accrued
benefit”
shall
mean
the
difference
between
the
Employee’s
total
accrued
benefit
under
Title
III
and
his
actual
accrued
benefit
under Title III.
For this purpose, an Employee’s
“total accrued benefit under Title
III” is the
benefit he would
have if his
accrued benefit were
determined under the
provisions of Title III but with the following modifications:
(i)
Include
in
Compensation
salary
that
would
have
been
paid
to
the
Employee
but
for
the
fact
that
he
voluntarily
elected
to
defer
receipt
of
that
salary
under
the
terms
of
KEDCP
or
a
similar
predecessor
program
but
only
if
such
salary
is
not
included
in
Compensation
for
purposes
of
calculating
the
Title
III
accrued
benefit
due
to
the
election
to
defer.
If
applicable,
include
the
deferred
salary
in
the
calendar
month
and
year
in
which the salary would have been paid had it not been deferred.
(ii)
Disregard
the
limitation
on
compensation
related
to
Code
section
401(a)(17).
(iii)
Disregard the limitation on benefits related to Code section 415.
(e)
“Title
IV-related
accrued
benefit”
shall
mean
the
difference
between
the
Employee’s
total
accrued
benefit
under
Title
IV
and
his
actual
accrued
benefit
under Title IV.
For this purpose, an Employee’s “total accrued benefit under
Title
Exhibit 10.10.1
10
IV” is the benefit
he would have if
his accrued benefit
were determined under
the
provisions of Title IV but with the following modifications:
(i)
Include
in
Compensation
salary
that
would
have
been
paid
to
the
Employee
but
for
the
fact
that
he
voluntarily
elected
to
defer
receipt
of
that
salary
under
the
terms
of
KEDCP
or
a
similar
predecessor
program
but
only
if
such
salary
is
not
included
in
Compensation
for
purposes
of
calculating
the
Title
IV
accrued
benefit
due
to
the
election
to
defer.
If
applicable,
include
the
deferred
salary
in
the
calendar
month
and
year
in
which the salary would have been paid had it not been deferred.
(ii)
Include
in
Compensation
any
Incentive
Compensation
Plan
award
that
would have
been paid
to the
Employee but
for the
fact that
he voluntarily
elected
to
defer
receipt
of
that
award
under
the
terms
of
KEDCP
or
a
similar
predecessor
program
but
only
if
such
award
is
not
included
in
Compensation for purposes of
calculating the Title
IV accrued benefit due
to
the
election
to
defer.
If
applicable,
include
the
deferred
award
in
the
calendar month
and year
in which
the award
would have
been paid
had it
not been deferred.
(iii)
Include in
Compensation
the
value
of
any
special
award specified
by
the
Committee
under
the
terms
of
the
special
award
to
be
included
for
compensation
purposes
under Title
IV
in
the
calendar
month
and
year
in
which any
applicable restrictions
on the
award lapse or,
if deferred,
in the
calendar month
and year
in which
any applicable
restrictions would
have
lapsed absent an election to defer.
(iv)
Disregard
the
limitation
on
compensation
related
to
Code
section
401(a)(17).
(v)
Disregard the limitation on benefits related to Code section 415.
(vi)
With
regard
to
a
Schedule
B
Employee,
determine
service
credited
for
purposes
of
benefit
accrual
as
if
time
served
while
on
a
Canada
payroll
were
time
served
on
a
United
States
payroll;
provided,
however,
that,
if
benefit accrual is at any time frozen under Title IV,
no further service shall
be credited from the time such freeze shall become effective.
Exhibit 10.10.1
11
(f)
Each of the components of the
accrued benefit under this Plan
(the Title I-related
accrued
benefit,
the
Title
II-related
accrued
benefit,
the
Title
III-related
accrued
benefit,
and
the
Title
IV-related
accrued
benefit)
shall
be
expressed as
a
straight
life
annuity
starting
at
the
age
that
is
the
normal
retirement
age
under
the
applicable title of the Retirement Plan in accordance with the following rules:
(i)
If the annuity
starting date
for the relevant
Retirement Plan
benefit occurs
on or before
the required
commencement date
under this
Plan, the
Title
I-
related
accrued
benefit,
the
Title
II-related
accrued
benefit,
the
Title
III-
related
accrued
benefit,
or
the
Title
IV-related
accrued
benefit,
as
is
applicable,
shall
first
be
calculated
as
of
the
Retirement
Plan
annuity
starting date related
to that
component benefit and
then shall be
converted
actuarially
to
a
straight
life
annuity
payable
at
age
65
applying
actuarial
assumptions
that
are
consistent
with
the
relevant
Title
of
the
Retirement
Plan.
The component accrued benefit
so calculated shall not
be increased
or decreased based on subsequent events.
(ii)
If the annuity starting date
for the relevant Retirement Plan
benefit has not
occurred
on
or
before
the
required
commencement
date
under
this
Plan,
the Title
I-related accrued
benefit, the
Title
II-related accrued
benefit, the
Title III-related
accrued benefit, or
the Title
IV-related
accrued benefit,
as
is applicable, shall
be calculated
as if
the relevant
Retirement Plan benefit
had an annuity
starting date
and a form
of payment
that is
the same as
the
required commencement
date
and
form
of
payment
under this
Plan.
The
resulting
component
benefit
shall
then
be
converted
actuarially
to
an
equivalent
straight
life
annuity
starting
at
age
65,
and
the
component
accrued benefit so calculated shall be the component accrued benefit under
this
Plan
and
shall
not
be
increased
or
decreased
based
on
subsequent
events.
(g)
The
component
accrued
benefit
described
in
subsection
(f)
above
shall
be
converted
to
the
actual
benefit
paid
under
this
Plan
applying
the
methodology
specified in the applicable title of the Retirement Plan.
For this purpose, the terms
of the
applicable title
of the
Retirement Plan
are those
in effect
as of
the annuity
Exhibit 10.10.1
12
starting date
used in
this Plan.
If the
applicable title
of the
Retirement Plan
does
not provide a
methodology,
a reasonable methodology,
as determined by
the Plan
Administrator, shall be used.
SECTION III.
DEATH
BENEFIT
(a)
If a Schedule A Employee chooses a 50% joint and survivor annuity and dies after
the annuity
starting date
of that
benefit, the
spouse beneficiary
will be
entitled to
payments
under
this
Plan
that
are
50%
of
the
payments
due
the
Schedule
A
Employee under this Plan during his lifetime.
(b)
If
an
Employee
who
is
not
a
Schedule
A
Employee
dies
prior
to
the
date
his
accrued
benefit
under
this
Plan
would
otherwise
commence,
this
Plan
shall
provide
a
death
benefit
if
the
applicable
title
of
the
Retirement
Plan
provides
a
death benefit
under that
circumstance. Any
death benefit
under this
Plan shall
be
paid in a lump sum
on the first day of the
first calendar month after death.
If there
is a delay in payment
of the lump sum,
regardless of the reason, the
Plan shall not
make an
adjustment to
reflect the
time value
of
money.
In the
case of
a
Title
I-
related
accrued
benefit
for
an
Employee
who
terminated
employment
before
September 1, 2004,
the death benefit,
if any,
shall be converted
to a present
value
and paid
to the
surviving spouse.
Except as
described in
the preceding
sentence,
the
death
benefit
shall
be
the
present
value
of
the
Employee’s
entire
accrued
benefit under this Plan payable in accordance with the following rules:
(i)
The
present
value
shall
be
paid
to
the
Employee’s
named
primary
Beneficiary
or
Beneficiaries
or,
if
applicable,
to
the
Employee’s
named
contingent Beneficiary
or Beneficiaries
if the
Beneficiary or
Beneficiaries
were named in a manner acceptable to the Plan Administrator.
(ii)
If
the
Employee
had
not,
prior
to
his
death,
named
any
Beneficiary
in
a
manner
acceptable
to
the
Plan
Administrator,
the
present
value
shall
be
paid to the Employee’s estate.
(iii)
The
present
value
shall
be
paid
in
a
lump
sum
and
shall
be
calculated
using
the
first
of
the
month
after
death
as
the
annuity
starting
date
and
Exhibit 10.10.1
13
applying
the
rules
described
in
Section
II(f)
and
(g)
of
this
Plan
for
determining the amount to be paid.
(iv)
If
a
beneficiary
makes
a
“qualified
disclaimer”
as
that
term
is
defined
in
section
2518
of
the
Code,
and
the
Plan
Administrator
receives
a
copy
of
the
disclaimer
within
9
months
after
the
employee’s
death
and
before
payment of the death benefit under this Plan, at the place designated by the
Plan
Administrator,
the
Plan
will
be
administered
as
if
the
disclaiming
beneficiary had died before the Employee.
SECTION IV.
Special Provisions for Certain Heritage Employees
(a)
Special
Provision
for
Former
ARCO
Alaska
Employees.
Notwithstanding
any
provisions
to
the
contrary,
in
order
to
comply
with
the
terms
of
the
Board
approved Master Purchase
and Sale Agreement
(“Sale Agreement”) by
which the
Company
acquired
certain
Alaskan
assets
of
Atlantic
Richfield
Company,
Inc.
(“ARCO”), the following supplemental payments will be made:
(i)
The
payments
which
would
have
been
received
under
Article
XXIV
–
ARCO
Flight
Crew
of
Title
I of
the
Retirement
Plan
for
those
who
were
classified
as
an
Aviation
Manager,
Chief
Pilot,
Assistant
Chief
Pilot,
Captain
or
Reserve
Captain
as
of
July
31,
2000
if
they
had
been
eligible
for those
benefits under
Title
I of
the Retirement
Plan, except
that if
they
receive
a
limited
social
security
makeup
benefit
from
Title
I
of
the
Retirement Plan it will be offset from the benefit payable from the Plan.
(ii)
A
final
ARCO
Supplemental
Executive
Retirement
Plan
(SERP)
benefit
will
be
calculated
at
the
earlier
of
the
time
an
Employee
who
had
an
ARCO
SERP
benefit
terminates
employment
or,
2
years
following
the
ARCO/BP
Amoco p.l.c.
merger,
April
17, 2002
(“calculation date”).
The
SERP benefit attributable to service through July 31, 2000 shall
be paid by
BP Amoco
p.l.c. and
the difference
shall be
paid by
this Plan.
The SERP
calculation will be done
as if the Employee
had continued to participate
in
the
Atlantic
Richfield
Retirement
Plan
and
SERP
up
to
the
calculation
date. The ARCO Annual Incentive Plan (AIP) amount used will be:
Exhibit 10.10.1
14
(A)
If
the
Employee
terminates
employment
involuntarily
prior
to
April
17,
2002,
the
highest
of
the
actual
AIP
in
the
last
3
years
including
the
AIP
target
payment
amount
for
years
after
1999
or
the
payment
received
under
Phillips
Annual
Incentive
Compensation Plan.
(B)
If the
Employee terminates
employment voluntarily
prior to
April
17,
2002,
or
if
the
calculation
is
made
as
of
April
17,
2002,
then
the AIP will include the highest 3 year average using
the highest of
the
actual
AIP,
the
AIP
target
payment
amount
for
years
after
1999,
or
the
payment
received
under
Phillips
Annual
Incentive
Compensation
Plan.
Any
benefit
paid
by
this
Plan
under
this
Section
IV(b)(ii)
and
the
SERP
benefit
paid
by
BP
Amoco
p.l.c.
shall offset the benefit payable from this Plan.
(b)
Special Provision
for Select
Heritage Burlington
Resources Employees
in Canada.
With regard to the employees listed on Schedule C, the following shall apply:
(i)
The Schedule C Employee will become a Participant in the Plan, solely for
the
purpose
of
providing
a
further
benefit
(the
“Additional
Benefit”),
calculated
in
accordance
with
the
provisions
of
this
subsection
IV(b).
Payment of
the Additional
Benefit shall
be made
at the
same time
and in
the
same
form
as
the
benefits
paid,
or
payable,
under
the
MSBP
with
regard to Non-Grandfathered Benefits, as that term is used in the MSBP.
(ii)
Additional Benefit
shall mean
the difference
between the
Putative MSBP
Benefit and the Offsetting Benefits, both as described below.
The Putative
MSBP
Benefit
shall
mean
the
difference
between
the
Schedule
C
Employee’s
total
accrued
benefit
under
Title
VI
of
the
CPRP
and
his
actual
accrued
benefit
under
Title
VI.
For
this
purpose,
a
Schedule
C
Employee’s
“total
accrued
benefit
under
Title
VI”
is
the
accrued
benefit
he would have if his accrued benefit under Title
VI were determined under
the terms of Title VI but with the following modifications:
Exhibit 10.10.1
15
(A)
Include
in
Annual
Earnings
any
compensation
included
under
the
MSBP,
including
it
in
the
calendar
year
to
which
it
would
have
been credited under the MSBP.
(B)
Disregard the
limitations on
compensation related
to Code
section
401(a)(17).
(C)
Disregard the limitation on benefits related to Code section 415.
(D)
Determine
service
credited
for
purposes
of
benefit
accrual
by
taking
into
account
any
service
granted
to
the
Schedule
C
Employee
and
any
benefit
formula
adjustments
required
by
an
employment
contract
with
the
Employer;
provided,
further,
that
with regard
to a
Schedule C
Employee, determine
service credited
for purposes of benefit
accrual as if time
served while on a
Canada
payroll
were
time
served
on
a
United
States
payroll;
provided,
however,
that,
if
benefit
accrual
is
at
any
time
frozen
under
Title
VI,
no
further
service
shall
be
credited
from
the
time
such
freeze
shall become effective.
Furthermore,
in
determining
the
Additional
Benefit,
paragraphs
(f)
and
(g)
of
Section
II
of
the
Plan
shall
apply;
provided, that,
such paragraph
(f) shall
be construed
as if
the Title
VI
related
benefit
described
in
this
paragraph
were
among
the
CPRP Titles listed in such paragraph (f).
(iii)
The Offsetting
Benefits shall
mean any
benefit, other
than the
Additional
Benefit,
provided
to
the
Schedule
C
Employee
under
a
defined
benefit
plan
of
ConocoPhillips,
including
but
not
limited
to
the
ConocoPhillips
Retirement
Plan
(and
any
successor
plan),
the
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan
(and
any
successor
plan),
and
the
Burlington
Resources
Inc.
Management
Supplemental
Benefits
Plan
(and any
successor plan);
provided, however,
that a
benefit plan
shall not
be
considered
unless
it
is
subject
to
the
Employee
Retirement
Income
Security Act of 1974, as
amended (ERISA) and is a
“defined benefit plan”
(as defined in section 3(35) of
ERISA), including any such plan regardless
Exhibit 10.10.1
16
of whether it
might also be
considered an “excess
benefit plan” as
defined
in section 3(36) of ERISA.
Nothing
in
this
subsection
IV(b)
is
intended
to
affect
the
other
operations
or
provisions of the Plan.
If the Schedule C Employee is, under the provisions of the
Plan, otherwise
eligible to
participate in
the Plan,
the Schedule
C Employee
will
do so in accordance with those provisions.
SECTION V.
Payment of Benefits.
(a)
Schedule A Employees
(i)
With
respect
to
a
Schedule
A
Employee,
the
accrued
benefit
under
this
Plan shall
be paid
as a
straight life
annuity for
the life
of the
Schedule A
Employee
commencing
in
December,
2005,
or
if
later,
six
months
after
Separation
from
Service.
The
annuity
starting
date
for
calculating
the
Title I-related and Title
IV-related
component annuity shall be the annuity
starting
date
used
in
determining
the
Schedule
A
Employee’s
Title
I
or
Title
IV benefit,
as
applicable, and
the
Plan shall
pay interest
at a
rate of
3% per
annum on
each delayed
payment from
the annuity
starting date
to
December 1,
2005.
The
annuity starting
date
for
calculating the
Title
II-
related
component
annuity
shall
be
December
1,
2005,
or,
if
later
six
months after Separation from Service.
(ii)
Provided,
however,
notwithstanding
subsection
(a)(i),
a
Schedule
A
Employee has the following choice or choices:
(aa)
A
Schedule
A
Employee
who
is
married
may,
on
or
before
December
1,
2005,
elect,
in
writing,
to
receive
a
50%
joint
and
survivor
annuity
with
the
spouse
as
survivor
commencing
in
December, 2005,
with the
rules regarding
the annuity
starting date
and
the
payment
of
interest
being
as
described
in
subsection
(i)
above; or
(bb)
Any
Schedule
A
Employee
may
elect
on
or
before
December
1,
2005, to
cancel,
in writing,
participation in
this Plan
in which
case
the
Schedule
A
Employee
shall
receive
the
present
value
of
his
Exhibit 10.10.1
17
entire
accrued
benefit
under
this
Plan
on
or
before
December
31,
2005,
and
shall
thereafter
have
no
rights
or
benefits
under
this
Plan.
Provided, however, if
a Schedule A Employee is
rehired and
becomes employed
by the
Employer after
2005, he
may thereafter
accrue
a
new
benefit
under
this
Plan
unrelated
to
the
cancelled
benefit.
(aaa)
For
a
Title
I-related
accrued
benefit
and
a
Title
IV-related
accrued
benefit,
the
present
value
will
be
determined
applying
the
rules
regarding
the
annuity
starting
date
and
the payment of interest as described in subsection (a)(i).
(bbb)
For a Title II-related accrued benefit, the present value shall
be based
on the
value of
the Schedule
A Employee’s
Title
II-related cash balance account as of December 1, 2005.
(ccc)
If
a
Schedule
A
Employee
dies
after
electing
to
cancel
participation but before payment is made, the payment shall
be made to his estate on or before December 31, 2005.
(iii)
If
a
Schedule
A
Employee
is
rehired
after
2005
and
thereafter
accrues
a
benefit
in
this
Plan,
he
shall
not
be
considered
a
Schedule
A
Employee
with respect to such post-2005 accrued benefit.
(b)
Employees other
than Schedule
A Employees
-- With
respect to
Employees who
are not Schedule A Employees, the benefit under this Plan,
shall be calculated and
paid as follows:
(i)
Commencement --
Unless the
accrued benefit
has been
or will
be paid
on
account of the Employee’s
death as described in Section
III(b), the present
value
of
the
Employee’s
accrued
benefit
shall
be
paid
in
a
lump
sum
on
the
later
of:
the
Employee’s
Plan-age
55
or
the
first
day
of
the
seventh
calendar
month
after
the
Employee’s
Separation
from
Service;
but
in
no
event earlier than November 1, 2006.
(ii)
Annuity Starting Date for calculating the present value:
(aa)
If the applicable commencement date
for a Title
I-related or a Title
IV-related
accrued
benefit
is
the
first
day
of
the
seventh
calendar
Exhibit 10.10.1
18
month after Separation from Service,
the annuity starting date
used
in
calculating
the
present
value
shall
be
the
later
of:
the
Employee’s Plan-age
55 or the first
day of the first
calendar month
after
the
Employee’s
Separation
from
Service;
and
the
Plan
shall
pay
interest
from
the
annuity
starting
date
to
the
commencement
date
at
the
6
month
T-Bill
rate
(as
determined
by
the
Plan
Administrator)
in
effect
on
the
annuity
starting
date.
If
the
applicable
commencement
date
for
a
Title-II-related
accrued
benefit
is
the
first
day
of
the
seventh
calendar
month
after
Separation from Service, the annuity starting date shall be the same
as the commencement date.
(bb)
Except as
provided in
the second
sentence of
this subsection
(bb),
if
the
applicable
commencement
date
is
the
Employee’s
Plan-age
55
or
November
1,
2006,
the
annuity
starting
date
used
in
calculating
the
present
value
shall
be
the
same
as
the
commencement
date.
Provided,
however,
in
the
case
of
an
Employee
whose
Separation
from
Service
is
in
2006
and
whose
commencement
date
under
this
Plan
is
November
1,
2006,
the
annuity starting
date used
in calculating
the present
value shall
be
the later of:
the Employee’s
Plan-age 55 or the
first day of
the first
calendar month after
the Employee’s
Separation from Service;
and
the Plan
shall pay
simple interest
from the
annuity starting
date to
November
1,
2006,
at
the
6
month
T-Bill
rate
(as
determined
by
the Plan Administrator) in effect on the annuity starting date.
(iii)
Except
as
specifically
provided
in
subsections
(b)(ii)(aa)
and
(bb),
the
Plan shall
not make
an adjustment
of the
benefit to
reflect the
time value
of money if there is delay in paying the benefit for any reason.
SECTION VI.
Method of Providing Benefits.
(a)
Nonsegregation.
Amounts
deferred
pursuant
to
this
Plan
and
the
crediting
of
amounts
to
a
Participant’s
Deferred
Compensation
Accounts
shall
represent
the
Exhibit 10.10.1
19
Company’s
unfunded
and
unsecured
promise
to
pay
compensation
in
the
future.
With
respect to
said
amounts,
the
relationship
of the
Company
and
a
Participant
shall be
that of
debtor and
general unsecured
creditor.
While the
Company may
make investments for
the purpose of
measuring and meeting
its obligations under
this Plan
such investments shall
remain the sole
property of
the Company
subject
to claims of its creditors generally, and shall not be deemed to form or be included
in any part of the Deferred Compensation Accounts.
(b)
Funding.
It is
the intention
of the
Company that
this
Plan
shall be
unfunded for
federal tax
purposes and
for purposes
of Title
I of
ERISA.
All amounts
payable
under this
Plan
shall
be paid
solely
from
the
general assets
of
the
Company
and
any rights accruing to a Participant or Beneficiary under this Plan shall be those of
a
general
creditor;
provided,
however,
that
the
Company
may
establish
one
or
more
grantor
trusts
to
satisfy
part
or
all
of
the
Company's
Plan
payment
obligations so long as this
Plan remains unfunded for purposes of
sections 201(2),
301(a)(3), and 401(a)(1) of ERISA.
(c)
Effect
of
Taxation.
If
a
portion
of
a
Participant’s
Benefits
under
the
Plan
is
includible
in
income
under
Code
section
409A,
such
portion
shall
be
distributed
immediately to the Participant.
(d)
Acceleration of Payment of Benefits.
Notwithstanding any other provision of this
Plan to
the contrary,
except as
provided
in Section
XI(g) and
below,
in no
event
shall this
Plan permit
the acceleration
of the
time or
schedule of
any payment
or
distribution
under this
Plan, except
that
the
Plan
Administrator
may
accelerate
a
payment or distribution under this Plan to
comply with a certificate of divestiture,
as provided
in section
1.409A-3(j)(4)(iii) of
the Treasury
regulations.
Moreover,
if a
portion of
a
Participant's
Benefit (and
earnings,
gains, and
losses
thereon) is
includible
in
income
under
Code
section
409A,
then
such
portion
shall
be
distributed
immediately
to
the
Participant
in
accordance
with
section
1.409A-
3(j)(4)(vii) of the Treasury regulations.
SECTION VII.
Nonassignability.
Exhibit 10.10.1
20
The
interest
of
a
Participant
or
his
Beneficiary
or
Beneficiaries
hereunder
may
not
be
sold,
transferred,
assigned,
or
encumbered
in
any
manner,
either
voluntarily
or
involuntarily,
and
any
attempt
so
to
anticipate,
alienate,
sell,
transfer,
assign,
pledge,
encumber, or
charge the
same shall be null
and void; neither
shall the Benefits
hereunder
be
liable
for
or
subject
to
the
debts,
contracts,
liabilities,
engagements,
or
torts
of
any
person
to
whom
such
Benefits
or
funds
are
payable,
nor
shall
they
be
an
asset
in
bankruptcy or subject to garnishment, attachment, or other legal or equitable proceedings.
SECTION VIII.
Administration.
(a)
The
Plan
shall
be
administered
by
the
Plan
Administrator.
The
Plan
Administrator may
delegate to
employees of
the Company
or any
member of
the
Controlled
Group
the
authority
to
execute
and
deliver
such
instruments
and
documents,
to
do
all
such
acts
and
things,
and
to
take
such
other
steps
deemed
necessary,
advisable, or
convenient for
the effective
administration of
the Plan
in
accordance
with
its
terms
and
purpose,
except
that
the
Plan
Administrator
may
not
delegate
any
discretionary
authority
with
respect
to
substantive
decisions
or
functions regarding
the Plan
or Benefits
under the
Plan.
The Plan
Administrator
may designate
a third
party to
provide services
that may
include record
keeping,
Participant accounting, Participant communication, payment of installments
to the
Participant,
tax
reporting,
and
any
other
services
specified
in
an
agreement
with
such third
party.
The Plan
Administrator may
adopt such
rules, regulations,
and
forms
as
deemed
desirable
for
administration
of
the
Plan
and
shall
have
the
discretionary
authority
to
allocate
responsibilities
under
the
Plan
to
such
other
persons
as
may
be
designated.
The
Plan
Administrator
shall
have
absolute
discretion
in
carrying
out
its
responsibilities,
and
all
interpretations,
findings
of
fact
and
resolutions
described
herein
which
are
made
by
the
Plan
Administrator
shall be binding, final and conclusive on all parties.
The Plan
Administrator
and his
or her
delegates shall
serve without
bond
and without
compensation for
services under
this Plan.
All expenses
of the
Plan
Administrator and his or her delegates for services under this Plan shall be paid by
the
Company.
None
of
the
Plan
Administrator
or
his
or
her
delegates
shall
be
Exhibit 10.10.1
21
liable
for
any
act
or
omission
on
his
or
her
own
part
excepting
his
or
her
own
willful
misconduct.
Without
limiting
the
generality
of
the
foregoing,
any
such
decision
or
action
taken
by
the
Plan
Administrator
or
his
or
her
delegates
in
reliance
upon
any
information
supplied
by
an
officer
of
the
Company,
the
Company's
legal
counsel,
or
the
Company's
independent
accountants
in
connection
with
the
administration
of
this
Plan
shall
be
deemed
to
have
been
taken in good faith.
(b)
Any
claim
for
benefits
hereunder
shall
be
presented
in
writing
to
the
Plan
Administrator
for
consideration,
grant
or
denial.
In
the
event
that
a
claim
is
denied in
whole or
in part
by the
Plan Administrator,
the claimant,
within ninety
days
of
receipt
of
said
claim
by
the
Plan
Administrator,
shall
receive
written
notice of denial.
Such notice shall contain:
(1)
a statement of the specific reason or reasons for the denial;
(2)
specific
references
to
the
pertinent
provisions
hereunder
on
which
such
denial is based;
(3)
a description of any additional material or information necessary to perfect
the
claim
and
an
explanation
of
why
such
material
or
information
is
necessary; and
(4)
an
explanation
of
the
following
claims
review
procedure
set
forth
in
paragraph (c) below.
(c)
Any
claimant
who
feels
that
a
claim
has
been
improperly
denied
in
whole
or
in
part
by
the
Plan
Administrator
may
request
a
review
of
the
denial
by
making
written application to
the Trustee.
The claimant
shall have
the right
to review
all
pertinent documents
relating to
said claim
and to
submit issues
and comments
in
writing
to
the
Trustee.
Any
person
filing
an
appeal
from
the
denial
of
a
claim
must
do
so
in
writing
within
sixty
days
after
receipt
of
written
notice
of
denial.
The
Trustee
shall
render
a
decision
regarding
the
claim
within
sixty
days
after
receipt of
a request
for review,
unless special
circumstances require
an extension
of
time
for
processing,
in
which
case
a
decision
shall
be
rendered
within
a
reasonable time, but not later than 120
days after receipt of the request for
review.
The decision
of the
Trustee
shall be
in writing
and, in
the case
of the
denial of
a
Exhibit 10.10.1
22
claim in whole
or in part,
shall set forth
the same
information as is
required in
an
initial notice of denial by the Plan
Administrator, other than an
explanation of this
claims
review procedure.
The
Trustee
shall
have absolute
discretion
in
carrying
out its responsibilities to make
its decision of an appeal,
including the authority to
interpret and construe the terms hereunder, and all interpretations, findings of fact,
and the decision
of the Trustee
regarding the appeal
shall be final,
conclusive and
binding on all parties.
(d)
Compliance
with
the
procedures
described
in
paragraphs
(b)
and
(c)
shall
be
a
condition precedent to the filing of any
action to obtain any benefit or
enforce any
right which any
individual may claim
hereunder.
Notwithstanding anything to
the
contrary
in
this
Plan,
these
paragraphs
(b),
(c)
and
(d)
may
not
be
amended
without
the
written
consent
of
a
seventy-five
percent
(75%)
majority
of
Participants
and
Beneficiaries
and
such
paragraphs
shall
survive
the
termination
of this Plan until all benefits accrued hereunder have been paid.
(e)
Any payment to a Participant or Beneficiary,
all in accordance with the provisions
of
this
Plan,
shall
to
the
extent
thereof
be
in
full
satisfaction
of
all
claims
hereunder
against
the
Plan
Administrator,
the
Company
and
all
Participating
Subsidiaries,
any
of
which
may
require
such
Participant
or
Beneficiary
as
a
condition to
such payment
to execute
a receipt
and
release therefor
in such
form
as shall be
determined by the
Plan Administrator,
the Company or
a Participating
Subsidiary.
If a
receipt and
release is
required and
the Participant
or Beneficiary
(as
applicable)
does
not
provide
such
receipt
and
release
in
a
timely
enough
manner
to
permit
a
timely
distribution
in
accordance
with
the
general
timing
of
distribution
provisions
in
this
Plan,
the
payment
of
any
affected
distribution(s)
shall be forfeited.
(f)
Benefits under
this Plan
will be
paid only
if the
Plan Administrator
decides in
its
discretion
that
a
Participant
or
Beneficiary
is
entitled
to
the
Benefits.
Notwithstanding
the
foregoing
or
any
provision
of
this
Plan,
a
Participant
(or
other claimant)
must exhaust
all administrative
remedies set
forth in
this
Section
VIII
or
otherwise
established
by
the
Plan
Administrator
before
bringing
any
action
at
law
or
equity.
Any
claim
based on
a
denial of
a
claim
under this
Plan
Exhibit 10.10.1
23
must be brought
no later
than the date
which is two
(2) years after
the date
of the
final denial of a claim under this Section VIII.
Any claim not brought within such
time shall be waived and forever barred.
SECTION IX.
Rights of Employees and Participants.
Nothing
contained in
the
Plan
(or
in
any
other
documents
related
to
this
Plan
or
to
any
Benefit
under
the
Plan)
shall
confer
upon
any
Employee
or
Participant
any
right
to
continue in the employ or
other service of the Company
or any member of the
Controlled
Group
or
constitute
any
contract
or
limit
in
any
way
the
right
of
the
Company
or
any
member of
the Controlled
Group to
change such
person's compensation
or other
benefits
or position or to terminate the employment of such person with or without cause.
SECTION X.
Amendment and Termination.
The Board reserves
the right
to amend this
Plan from time
to time,
to terminate this
Plan
entirely
at
any
time,
and
to
delegate
such
authority
as
the
Board
deems
necessary
or
desirable;
provided,
however,
that
no
amendment
may
affect
the
balance
in
a
Participant’s
account on
the effective
date
of
the
amendment; and,
further
provided, the
Company shall remain
liable for any
Benefits accrued under
this Plan prior
to the date
of
amendment or termination.
SECTION XI.
Miscellaneous Provisions.
(a)
Except
as
otherwise
provided
herein,
the
Plan
shall
be
binding
upon
the
Company,
its successors and
assigns, including but
not limited to
any corporation
which may acquire all or
substantially all of the Company's
assets and business or
with or into which the Company may be consolidated or merged.
(b)
The
Plan
shall
be
construed,
regulated,
and
administered
in
accordance
with
the
laws of the State of Texas
except to the extent that said laws have been preempted
by
the
laws
of
the
United
States.
The
forum
and
venue
for
any
suit
brought
regarding any claim under this Plan shall be in Harris County, Texas.
Exhibit 10.10.1
24
(c)
If
any
provision
of
this
Plan
shall
be
held
illegal
or
invalid
for
any
reason,
said
illegality
or
invalidity
shall
not
affect
the
remaining
provisions
hereof;
instead,
each
provision
shall
be
fully
severable,
and
this
Plan
shall
be
construed
and
enforced as if said illegal or invalid provision had never been included herein.
(d)
For
purposes
of
this
Plan,
electronic
communications
and
signatures
shall
be
considered to be
in writing if
made in conformity
with procedures which
the Plan
Administrator may adopt from time to time.
(e)
The
Plan
Administrator,
in
its
sole
discretion,
may
direct
that
a
payment
to
be
made
to
an
incompetent
or
disabled
person,
whether
because
of
minority
or
mental
or
physical
disability,
instead
be
made
to
the
guardian
or
legal
representative
of
such
person
or
to
the
person
having
custody
of
such
person
(unless prior
claim therefor
shall have
been made
by a
duly qualified
guardian or
other
legal
representative),
without
further
liability
either
on
the
part
of
the
Company
or
a
Participating
Subsidiary
or
the
Plan
for
the
amount
of
such
payment
to
the
person
on
whose
benefit
such
payment
is
made.
Any
payment
made
in
accordance
with
the
provisions
of
this
provision
shall
be
a
complete
discharge
of
any
liability
of
the
Company,
its
Subsidiaries,
and
this
Plan
with
respect to the Benefits so paid.
(f)
Payment
of
Plan
Benefits
may
be
subject
to
administrative
or
other
delays
that
result
in
payment
to
the
Participant
or
his
beneficiaries
on
a
date
later
than
the
date
specified in
this
Plan
or
the
Participant's
Election Form.
Any
such
payment
delays
will
comply
with
Code
section
409A
of
the
Code,
including
without
limitation
section
1.409A-2(b)(7)
of
the
Treasury
regulations.
No
Participant
or
Beneficiary
shall
be
entitled
to
any
additional
earnings
or
interest
in
respect
of
any such payment delays, nor shall any Participant or Beneficiary be provided any
election with respect to the timing of any delayed payment.
(g)
If
all
or
any
part
of
any
Participant's
or
Beneficiary's
Benefits
hereunder
shall
become subject to any estate, inheritance, income, employment
or other tax which
the
Company
shall
be
required
to
pay
or
withhold,
the
Company
shall
have
the
full power
and authority
to withhold
and pay
such tax
out of
any monies
or other
property
held
for
the
account
of
the
Participant
or
Beneficiary
whose
interests
Exhibit 10.10.1
25
hereunder
are
so
affected
(including,
without
limitation,
by
reducing
and
offsetting the
Participant's or
Beneficiary's account
balance). Prior
to making
any
payment,
the
Company
may
require
such
releases
or
other
documents
from
any
lawful taxing authority as it shall deem necessary or desirable.
(h)
No
amount
accrued
or
payable
hereunder
shall
be
deemed
to
be
a
portion
of
an
Employee's
compensation
or
earnings
for
the
purpose
of
any
other
employee
benefit
plan
adopted
or
maintained
by
the
Company,
nor
shall
this
Plan
be
deemed to amend or modify the provisions of the Retirement Plan.
(i)
This
Plan
is
intended
to
meet
the
requirements
of
Code
section
409А,
as
applicable,
in
order
to
avoid
any
adverse
tax
consequences
resulting
from
any
failure
to
comply
with
Code
section
409А
and,
as
a
result,
this
Plan
shall
be
operated
in
a
manner
consistent
with
such
compliance.
Except
to
the
extent
expressly set forth in this
Plan, the Participant (and/or the Participant's
Beneficiary,
as applicable)
shall have
no right
to dictate
the taxable
year in
which any
payment
hereunder that is subject to Code section 409А should be paid.
(j)
At the Effective
Time, certain
active employees of
Phillips 66 and
members of its
controlled
group
ceased
to
participate
in
the
Plan,
and
the
liabilities,
including
liabilities related to
benefits grandfathered from Code
section 409A (
i.e.
, amounts
deferred
and
vested
prior
to
January
1,
2005),
for
these
participant's
benefits
under the Plan were transferred to the members of the Phillips 66 controlled group
and
continued
as
the
Phillips
66
Key
Employee
Supplemental
Retirement
Plan.
ConocoPhillips
distributed its
interest
in
Phillips
66
to
its
shareholders
as
of
the
Distribution.
Notwithstanding
Section
X,
on
and
after
the
Effective
Time,
the
Company,
ConocoPhillips,
other
members
of
the
Controlled
Group
(as
determined after
the Distribution),
the Plan,
any directors,
officers,
or employees
of
any
member
of
the
Controlled
Group
(as
determined
after
the
Distribution),
and
any
successors
thereto,
shall
have
no
further
obligation
or
liability
to,
or
on
behalf
of,
any
such
participant
with
respect
to
any
benefit,
amount,
or
right
transferred
to
or
due
under
the
Phillips
66
Key
Employee
Supplemental
Retirement Plan.
Exhibit 10.10.1
26
SECTION XI.
Effective Date of the Restated Plan.
The
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan
is
hereby
amended
and restated as set forth in
this 2020 Amendment and Restatement
effective as of January
1, 2020 and conditioned on the occurrence of the Distribution.
Executed this ____ day of December 2019, by a duly authorized officer of the Company.
Heather G. Sirdashney
Vice President, Human Resources
KESRP
2020 Restatement
12-19-2019
Exhibit 10.10.1
27
APPENDIX A
SELECT NEW HIRES TO
CONOCOPHILLIPS KEY EMPLOYEE SUPPLEMENTAL
RETIREMENT
PLAN
For Select New Hires, as set forth in
resolutions adopted from time to time by
the Human
Resources and Compensation
Committee of the
Board of Directors of
ConocoPhillips, or
its successor, the following provisions apply:
1.
The
Select
New
Hire
will,
effective
on
the
first
day
of
employment
with
the
Controlled
Group,
become
a
Participant
in
the
ConocoPhillips
Key
Employee
Supplemental
Retirement
Plan.
In
addition
to
the
benefits
provided
under
the
Plan,
the
Select New Hire will be eligible for a further benefit
(the "Further Benefit"), calculated in
accordance with the provisions of this Appendix.
2.
Further Benefit shall
mean the difference
between the Putative
Title I
Benefit and
the
Offsetting
Benefits,
both
as
described
below.
In
determining
the
Further
Benefit,
paragraphs (f) and (g) of the Plan shall apply.
3.
The Putative Title I Benefit shall mean the sum of (i), (ii), and (iii) below:
(i.)
The difference
between the
Select New
Hire's total
accrued benefit
under
Title
I
and
his
actual
accrued
benefit
under
Title
I.
For
this
purpose,
a
Select New Hire's
total accrued benefit
under Title
I is the
accrued benefit
he would
have if
his accrued
benefit under
Title
I were
determined under
the terms of Title I but with the following modifications:
(aa)
Include
in
Annual
Earnings
an
award
under
the
Incentive
Compensation Plan
which the
Select New
Hire deferred
under the
terms of KEDCP.
Include such award in the calendar year in which
the
award
would
have
been
paid
to
the
Select
New
Hire
if
it
had
not been deferred.
(bb)
Include in Annual Earnings salary that would have been paid to
the
Select New Hire but for
the fact that he voluntarily
elected to defer
receipt
of
that
salary
under
the
terms
of
KEDCP.
Include
the
Exhibit 10.10.1
28
deferred
salary
in
Annual
Earnings
in
the
calendar
year
in
which
the salary would have been paid had it not been deferred.
(cc)
Include in Annual Earnings
the initial value
of a restricted stock
or
restricted stock unit award under
the Incentive Compensation Plan.
Include
that
value
in
Annual
Earnings
in
the
calendar
year
in
which the award was granted.
(dd)
Include
in
Annual
Earnings
the
value
of
any
special
award
specified by the Committee under the
terms of the special
award to
be included for
Annual Earnings purposes
under Title
I in the
year
in
which
any
applicable
restrictions
on
the
award
lapse
or,
if
deferred,
in
the
year
in
which
any
applicable
restrictions
would
have lapsed absent an election to defer.
(ee)
Disregard the
limitations on
compensation related
to Code
section
401(a)(17).
(ff)
Disregard the limitation on benefits related to Code section 415.
(gg)
If
the
Select
New
Hire
is
eligible
to
receive
benefits
under
the
ConocoPhillips
Executive
Severance
Plan
or
under
the
ConocoPhillips Key
Employee Change in
Control Severance
Plan,
include in
Annual Earnings
an amount
determined by
dividing the
Select New
Hire's Salary
by 4.3333
times the
number of
weeks or
partial
weeks
from
the
date
the
Select
New
Hire's
employment
ends with the
Employer to
the end
of that
calendar year.
Provided,
however, this
subsection (gg) shall
be disregarded to
the extent the
benefit
created
solely
by
operation
of
this
subsection
(gg)
is
provided under the terms of Title 1.
(hh)
Determine service credited
for purposes of
benefit accrual as
if the
Select
New
Hire
had
originally
been
employed
by
the
Controlled
Group
on
the
date
that
the
Select
New
Hire
began
employment
with the
company with
which the
Select New
Hire was
employed
immediately prior to becoming employed by the Controlled Group.
Exhibit 10.10.1
29
(ii.)
In the
case of
a Select
New Hire
who terminated
employment on
or after
February
8,
1993,
the
Title
I-related
accrued
benefit
shall
include
an
additional supplemental accrued benefit calculated under the terms of Title
I,
but
disregarding
the
limitation
on
compensation
that
is
taken
into
account, using as final average earnings
the difference, if any,
between the
Total
Final
Average
Earnings
and
the
Final
Average
Earnings
used
in
Title 1.
(iii.)
The Title
I-related accrued
benefit shall
also include
any benefit
provided
under Section IV of this Plan.
4.
The
Offsetting
Benefits
shall
mean
any
benefit,
other
than
the
Further
Benefit,
provided
to
the
Select
New
Hire
under
a
defined
benefit
plan
of
ConocoPhillips,
including but not
limited to the ConocoPhillips
Retirement Plan (and any
successor plan)
and the ConocoPhillips Key Employee
Supplemental Retirement Plan (and any
successor
plan), together with any
benefit provided to the
Select New Hire under
a "defined benefit
plan"
(as
defined
in
section
3(35)
of
the
Employee
Retirement
Income
Security
Act
of
1974, as amended
(ERISA)), including
any such
plan regardless of
whether it
might also
be
considered
an
"excess
benefit
plan"
as
defined
in
section
3(36)
of
ERISA,
of
the
company by which the Select New
Hire was employed immediately prior
to becoming an
employee of
the Controlled
Group. In
determining the
value of
a benefit
provided by
an
employer
which
is
not
a
member
of
the
Controlled
Group,
the
Plan
Administrator
may
make any reasonable assumptions necessary and
use such information as may be
publicly
available, provided by
such employer,
or provided by
the Select New
Hire, although
it is
within the
discretion of
the Plan
Administrator to
determine which
such information
and
assumptions
to
use
and
to
disregard
any
information
which
the
Plan
Administrator
considers invalid, incomplete, or otherwise suspect.
5.
Nothing in
this
Appendix is
intended to
affect the
other operations
or provisions
of the Plan. If the
Select New Hire is,
under the provisions
of the Plan, otherwise
eligible
to
participate
in
the
Plan,
the
Select
New
Hire
will
do
so
in
accordance
with
those
provisions.
Exhibit 10.10.1
30
Schedule A
Name
Employee
Number
BUSH, BRUCE ASHBY
123432
FORD, RONALD F
280903
GILL, DAVID
CLINTON
311219
HAGENSON, RANDY L
341865
BRAND, KAREN FLENNIKEN
365245
KREMER, DON F
492288
LAMPERT,
HARRY T
498780
DAVIDSON,
LINDA LAWSON
507761
MCKEE, JOSEPH MASON
580382
MOORE, STANLEY WAYNE
118400
MULLENS, PATRICK
O
624406
RISLEY,
ALLYN WAYNE
735419
SIGLER III, CARL BENJAMIN
793759
SIMPSON, JAMES ALEX
796245
SMITH, ALBERT GORIN, JR.
802659
SQUIRES, TOMMY DALE
824971
BALL, REBECCA P
880394
WISZNEAUCKAS, ERIC COOK
961604
WREN, CHRISTOPHER LYNDE
970988
MACKLIN, DONALD L
541514
JOHNSON, DAVID ALAN
898304
HARPER, MARK R
483674
PARKER, CHARLES M
615208
NELSON, DAVID
016221
DURBIN, JOHN E
017871
LINES, JOHN F
012019
LOFTUS, THOMAS A. III
017554
JAMES, FRANCIS H
013118
MADISON, PAUL A.
015570
SPOON, MARK J.
018451
GRIMMER, PAUL J
015564
Exhibit 10.10.1
31
Schedule B
Name
Employee Number
Kennedy, Shawn R.
897261
O’Connell, Patrick J.
302463
Exhibit 10.10.1
32
Schedule C
Name
Employee Number
Midkiff, Kevin L.
108989
Stansbury, Jeffery N.
109404
Casey B. Jones
18303
EX-10.11.1
Exhibit 10.11.1
1
DEFINED CONTRIBUTION MAKE-UP PLAN
OF
CONOCOPHILLIPS
TITLE I
(Effective for benefits earned and vested prior to
January 1, 2005)
2020 AMENDMENT AND RESTATEMENT
The Defined
Contribution Make-Up
Plan of
ConocoPhillips,
Title
I (the
“Frozen Plan”),
is
hereby
amended
and
restated
effective
as
of
January
1,
2020
(except
where
another
date is specified herein with regard to a particular provision).
Immediately prior to
effectiveness of
this 2020
Amendment and Restatement,
the Frozen
Plan was and remains subject to the 2012 Restatement of the Defined Contribution Make-
Up
Plan
of
ConocoPhillips,
Title
I,
which
was
effective
as
of
the
"Effective
Time"
defined in the Employee
Matters Agreement by and
between ConocoPhillips and Phillips
66
(the
"Effective
Time"),
together
with
the
First
Amendment
to
Title
I
of
the
Defined
Contribution Make-Up Plan of
ConocoPhillips (2012 Restatement), effective
October 30,
2019.
Preamble
The purpose of this Plan is to attract and retain key
employees by providing supplemental
benefits
for
those
Eligible
Employees
whose
benefits
under
the
CPSP
might
otherwise
have
been
affected
by
Pay
Limitations
or
by
a
voluntary
reduction
in
salary
under
provisions of KEDCP.
The Defined Contribution Make-Up Plan of ConocoPhillips is intended to provide
certain
specified
benefits
to
Highly
Compensated
Employees
whose
benefits
under
the
ConocoPhillips Savings
Plan might
otherwise be
limited.
Title
I of
the Plan,
sometimes
referred to as the
Frozen Plan, is
effective with regard to
benefits earned and
vested prior
to January 1, 2005,
while Title
II of the Plan,
sometimes referred to as
the Ongoing Plan,
Exhibit 10.11.1
2
is effective
with regard
to benefits
earned or
vested after
December 31,
2004.
Earnings,
gains,
and
losses
shall
be
allocated
to
the
Title
of
the
Plan
to
which
the
underlying
obligations
giving
rise to
them are
allocated.
Other than
earnings, gains,
and losses,
no
further benefits shall accrue under Title I of this Plan after December 31, 2004.
This
Title
I
of
the
Plan
is
intended
(1)
to
be
a
“grandfathered”
plan
pursuant
to
Code
section 409A, as
enacted as
part of the
American Jobs
Creation Act of
2004, and
official
guidance issued thereunder,
and (2) to be “a plan
which is unfunded and is maintained
by
an
employer
primarily
for
the
purpose
of
providing
deferred
compensation
for
a
select
group of management
or highly compensated
employees” within the
meaning of sections
201(2), 301(a)(3),
and 401(a)(1)
of ERISA.
Notwithstanding any
other provision
of this
Plan,
this
Plan
shall
be
interpreted,
operated,
and
administered
in
a
manner
consistent
with these intentions.
Section 1.
Definitions.
For
purposes
of
the
Plan,
the
following
terms,
as
used
herein,
shall
have
the
meaning
specified:
(a)
“Affiliated
Company”
shall
mean
ConocoPhillips
and
any
company
or
other
legal entity that is controlled, either directly or indirectly, by ConocoPhillips.
(b)
“Affiliated Group”
shall mean
ConocoPhillips and
its subsidiaries
and affiliates
in which it owns a 5% or more equity interest.
(c)
“Allocation
Ratio”
shall
mean
the
ratio
determined
by
dividing
(i)
an
amount
equal
to
the
total
value
of
the
unallocated
shares
of
Stock
allocated
to
Stock
Savings
Feature
participants
and
beneficiaries
as
of
a
Stock
Savings
Feature
Semiannual
Allocation
Date
or
Supplemental
Allocation
Date
(as
defined
in
the
CPSP)
by
(ii)
an
amount
equal
to
the
total
net
Stock
Savings
Feature
employee
deposits
used
in
the
calculation
of
the
Stock
Savings
Feature
Semiannual
Allocation or Supplemental Allocation (as defined in the CPSP).
(d)
“Beneficiary”
shall
mean
a
person
or
persons
or
the
trustee
of
a
trust
for
the
benefit
of
a
person
designated
by
a
Participant
to
receive,
in
the
event
of
death,
any
unpaid
portion
of
a
Participant's
Benefit
from
this
Plan,
as
provided
in
Exhibit 10.11.1
3
Section 5.1.
(e)
“Benefit”
shall
mean
an
obligation
of
the
Company
to
pay
amounts
from
the
Frozen Plan.
(f)
“Board”
shall
mean
the
Board
of
Directors
of
the
Company,
as
it
may
be
comprised from time to time.
(g)
“Code”
shall mean the
Internal Revenue Code
of 1986,
as amended from
time to
time, or any successor statute.
(h)
“Committee”
shall mean the Nonqualified Plans Benefit
Committee as appointed
from
time
to
time
by
the
Board;
provided,
however,
that
until
a
successor
is
appointed by
the Board,
the individual
serving as
the Company’s
Vice
President
with responsibility over human resources shall be sole member of the Committee.
(i)
“Company”
shall
mean
ConocoPhillips
Company,
a
Delaware
corporation,
or
any successor corporation.
The Company is a subsidiary of ConocoPhillips.
(j)
“Company Stock Fund”
shall mean an Investment
Option under this Plan
that is
accounted for as if
investments were made
in the common
stock, $0.01 par
value,
of
ConocoPhillips,
although
no
such
actual
investments
need
be
made,
with
accounting entries being sufficient therefor.
(k)
“ConocoPhillips”
shall
mean
ConocoPhillips,
a
Delaware
corporation,
or
any
successor
corporation.
ConocoPhillips
is
a
publicly
held
corporation
and
the
parent of the Company.
(l)
“CPSP”
shall mean the ConocoPhillips Savings Plan.
(m)
“CPSP Pay”
shall mean
"
Pay
"
as defined in the CPSP.
(n)
“DCMP
Pay”
shall
mean
"
Pay
"
as
defined
in
the
CPSP
without
regard
to
Pay
Limitations or voluntary salary reduction under provisions of the KEDCP.
(o)
“Disability”
shall
mean
the
inability,
in
the
opinion
of
the
Medical
Director
of
ConocoPhillips,
of
a
Participant,
because
of
an
injury
or
sickness,
to
work
at
a
reasonable occupation that is available with a member of the Affiliated Group.
(p)
“Election
Form”
shall mean
a
written
form,
including
one
in
electronic
format,
provided by
the Plan
Administrator pursuant
to which
a Participant
may elect
the
time and form of payment of his or her Benefits.
(q)
“Eligible
Employee”
shall
mean
an
Employee
whose
DCMP
Pay
exceeds
the
amount
set
forth
in
Code
section 401(a)(17),
as
amended
from
time
to
time,
or
Exhibit 10.11.1
4
who
is
eligible
to
elect
a
voluntary
salary
reduction
under
the
provisions
of
the
KEDCP.
(r)
“Employee”
shall
mean
any
individual
who
is
a
salaried
employee
of
the
Company or any Participating Subsidiary.
(s)
“ERISA”
shall mean
the Employee
Retirement Income
Security Act
of 1974,
as
amended from time to time, or any successor statute.
(t)
“Exchange
Act”
shall
mean
the
Securities
Exchange
Act
of
1934,
as
amended
and in effect from time to time, or any successor statute.
(u)
“Frozen
Plan”
shall mean
Title
I of
the Defined
Contribution
Make-Up Plan
of
ConocoPhillips.
(v)
“Investment
Options”
shall
mean
the
investment
options,
as
determined
from
time to
time by
the Plan
Administrator,
used to
credit earnings,
gains, and
losses
on Supplemental Thrift Feature Account and
Supplemental Stock Savings Feature
Account balances.
(w)
“KEDCP”
shall
mean
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips
or
any
similar
or
successor
plan
maintained
by
an
Affiliated
Company.
(x)
“Layoff”
or
“Laid
Off”
shall
mean
layoff
under
the
Phillips
Layoff
Plan,
the
Work
Force
Stabilization
Plan
of
Phillips
Petroleum
Company,
the
Phillips
Petroleum Company
Executive Severance
Plan, the
Conoco Severance
Pay Plan,
the
Conoco
Inc.
Key
Employee
Severance
Plan,
or
any
similar
plan
which
the
Company,
any Participating Subsidiary,
or a member of
the Affiliated Group
may
adopt
from
time
to
time
under
the
terms
of
which
the
Participant
executes
and
does
not
revoke
a
general
release
of
liability,
acceptable
to
the
Company,
Participating
Subsidiary,
or
a
member
of
the
Affiliated
Group,
as
applicable,
under such layoff plan.
(y)
“Ongoing
Plan”
shall mean
Title
II
of
the
Defined
Contribution
Make-Up
Plan
of ConocoPhillips.
(z)
“Other
Obligations”
shall
mean
the
"
Other
Obligations
"
as
defined
in
the
Amendment to and Merger of Amended and Restated Conoco Inc. Salary Deferral
&
Savings
Restoration
Plan
into
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips
and
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips,
Exhibit 10.11.1
5
pursuant
to
which
a
portion
of
the
Amended
and
Restated
Conoco
Inc.
Salary
Deferral & Savings
Restoration Plan is
merged into
this Plan effective
October 3,
2003.
(aa)
“Participant”
shall
mean
an
Eligible
Employee
who
is
eligible
to
receive
a
Benefit from
this
Plan as
a result
of being
an Eligible
Employee and
any
person
for
whom
a
Supplemental
Thrift
Feature
Account
and/or
a
Supplemental
Stock
Savings Feature Account is maintained.
(bb)
“Participating Subsidiary”
shall mean a Subsidiary which has adopted the CPSP
and of which one
or more Employees are
Participants eligible to make
deposits to
the CPSP or are eligible for Benefits pursuant to this Plan.
(cc)
“Pay
Limitations”
shall
mean
the
compensation
limitations
applicable
to
the
CPSP that are set forth in Code section 401(a)(17), as adjusted.
(dd)
“Plan”
shall
mean
the
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips.
The Plan is sponsored and maintained by the Company.
(ee)
“Plan Administrator”
shall mean the Committee.
(ff)
“Plan Year
”
shall mean January 1 through December 31.
(gg)
“Retirement”
shall
mean
termination
of
employment
with
the
Company,
a
Participating
Subsidiary,
or
a
member
of
the
Affiliated
Group
that
qualifies
the
Employee
for
Retirement
as
that
term
is
defined
in
the
applicable
provisions
of
the
ConocoPhillips
Retirement
Plan,
the
Retirement
Plan
of
Conoco,
or
of
the
applicable retirement plan
of a member
of the Affiliated
Group.
Notwithstanding
the
foregoing,
an
Employee
will
not
be
considered
to
be
in
Retirement
for
purposes
of
this
Plan
if
he
is
entering
Retirement
under
the
Retirement
Plan
of
Conoco
prior
to
age
55,
unless
he
had
attained
age
50
on
or
before
August
30,
2002.
(hh)
“Stock”
shall
mean
shares
of
common
stock,
$0.01
par
value,
issued
by
ConocoPhillips.
(ii)
“Stock Savings Feature”
shall mean the Stock Savings Feature of the CPSP.
(jj)
“Subsidiary”
shall mean any corporation
or other entity that
is treated as a
single
employer with
ConocoPhillips under
section 414(b)
, (c),
or (m)
of the
Code.
In
applying section
1563(a)(1), (2),
and (3)
of the
Code for
purposes of
determining
a
controlled
group
of
corporations
under
section
414(b)
and
for
purposes
of
Exhibit 10.11.1
6
determining
trades
or
businesses
(whether
or
not
incorporated)
under
common
control
under
regulation
section
1.414(c)-2
for
purposes
of
Code
section
414(c),
the
language
“at
least
80%”
shall
be
used
without
substitution
as
allowed
under
regulations pursuant to Code section 409A.
(kk)
“Supplemental Stock
Savings Contributions”
shall mean (i)
prior to
the month
in which the Participant’s
Pay first exceeds the Pay Limitations
in a year, for
each
month that the Participant makes
deposits to the Stock Savings
Feature, 1% of the
amount of
the Participant’s
voluntary salary
reduction under
the KEDCP
for that
month,
and
(ii)
provided the
Participant
is making
deposits
to the
Stock Savings
Feature in
the month
in which
the Participant’s
Pay exceeds
the Pay
Limitations,
for that
month and
for each
month thereafter
until the
end of
the year,
1% of
the
sum
of
the
amount
of
the
Participant’s
voluntary
salary
reduction
under
the
KEDCP
for
that
month
plus
the
amount
of
the
Participant’s
Pay
for
that
month
that is in excess of the Pay Limitations for that year.
(ll)
“Supplemental
Stock
Savings
Feature
Account”
shall
mean
the
Plan
Benefit
account
of
a
Participant
that
reflects
the
portion
of
his
or
her
Benefit
that
is
intended to replace certain Stock Savings Feature benefits to which the Participant
might otherwise be entitled
but for the application
of the Pay Limitations
and/or a
voluntary salary reduction under the KEDCP.
(mm)
“Supplemental
Thrift
Contributions”
shall
mean,
(i)
prior
to
the
month
in
which the
Participant’s
Pay first
exceeds the
Pay Limitations
in a
year,
the same
percentage
of
a
Participant’s
Pay
that
the
Participant
is
depositing
as
a
Basic
Deposit
to
the
Thrift
Feature
for
that
month
multiplied
by
the
amount
of
the
Participant’s voluntary
salary reduction under the
KEDCP for that
month, and (ii)
provided the
Participant is
making deposits
to the
Thrift Feature
for the
month in
which
the
Participant’s
Pay
exceeds
the
Pay
Limitations
and
each
month
thereafter until
the
end
of
the
year,
the
same
percentage
of
the
Participant’s
Pay
that the Participant
was depositing as
a Basic Deposit
to the Thrift
Feature for the
month in
which he
or she
reached the
Pay Limitations
for the
year, multiplied
by
the
sum
of
the
amount
of
the
Participant’s
voluntary
salary
reduction
under
the
KEDCP
for
that
month
plus
the
amount
of
the
Participant’s
Pay
for
that
month
that is in excess of the Pay Limitations for that year.
Exhibit 10.11.1
7
(nn)
“Supplemental Thrift Feature Account”
shall mean the Plan Benefit
account of
a Participant
which reflects
the portion
of his
or her
Benefit which
is intended
to
replace certain Thrift Feature benefits
to which the Participant
might otherwise be
entitled
but
for
the
application
of
the
Pay
Limitations
and/or
a
voluntary
salary
reduction under the KEDCP.
(oo)
“Thrift Feature”
shall mean the Thrift Feature of the CPSP.
(pp)
“Trustee”
shall mean the trustee of
the grantor trust established
for this Plan by a
trust agreement between the Company and the trustee, or any successor trustee.
(qq)
“Valuation
Date”
shall mean “Valuation
Date” as defined in the CPSP.
Section 2.
Eligibility.
Benefits may only be granted to Eligible Employees.
Section 3.
Supplemental Thrift Feature Account Benefits.
For each payroll period in
which Company Contributions to
a Participant's account in the
Thrift
Feature
are,
or
would
be,
limited
by
the
Pay
Limitations
and/or
by
a
voluntary
salary
reduction
to
the
KEDCP,
a
Benefit
amount
shall
be
credited
to
his
or
her
Supplemental
Thrift
Feature
Account
no
later
than
the
end
of
the
month
following
the
Valuation
Date that
Company
contributions
are
made
to
the
Participant’s
Thrift
Feature
Account, or would
be made to
such account but
for Pay Limitations.
The Participant will
be
credited
with
an
amount
equal
to
the
amount
of
his
or
her
Supplemental
Thrift
Contributions
each
month
to
the
same
investment
funds
and
in
the
same
proportions
as
the Participant
has directed
his or
her latest
available investment
allocation for
Deposits
to the Thrift Feature.
Section 3.1
Supplemental Thrift Feature Account Earnings
The
Supplemental
Thrift
Feature
Account
shall
be
eligible
to
be
invested
in
the
same
investment funds
as are
made available
to Participants
in the
Thrift Feature
from time
to
time.
While such
investments shall
consist solely
of book
entries and
shall not
actually
Exhibit 10.11.1
8
be invested in such funds, the book entry
share value of such deemed investment
funds in
this Plan
shall be
determined to
be the
same share
value as
the actual
value of
shares in
the
investment
funds
of
the
CPSP.
The
amounts
deemed
invested
in
this
Plan
shall
be
valued at the
same time and
in the same
manner as though
they were actually
invested in
the
CPSP.
Also,
deemed
investments
in
the
Participant’s
Supplemental
Thrift
Feature
Account may be
exchanged into
other available
investment funds
in the
same manner,
at
the same
times, and
subject to
the same
limitations as
though the
deemed amounts
were
actually
invested
in
the
CPSP.
However,
to
the
extent
that
earnings
in
the
form
of
dividends
on
Company
Stock
in
the
CPSP
are
eligible
to
be
passed
through
to
the
Participant, such dividends will be deemed to have been reinvested in the Company Stock
Fund
of
this
Plan,
without
regard
to
whether
the
Participant
has
made
a
pass
through
election under the CPSP.
Section 4.
Supplemental Stock Savings Feature Account Benefits.
For
each
month
in
which
a
Semiannual
Allocation
or
Supplemental
Allocation
(as
defined in the
CPSP) to
a Participant's
account in the
Stock Savings
Feature is, or
would
be,
limited
by
the
Pay
Limitations
and/or
by
a
voluntary
salary
reduction
under
the
KEDCP,
a
Benefit
amount
shall
be
credited
to
his
or
her
Supplemental
Stock
Savings
Feature Account. The amount
to be credited shall
be calculated in shares in
the Company
Stock Fund
of this
Plan as
though the
Participant had
made Supplemental
Stock Savings
Contributions
and
shall
be
equal
to
(i)
the
Participant's
Supplemental
Stock
Savings
Contributions during the applicable Allocation Period (as defined in the CPSP) multiplied
by the applicable Allocation Ratio,
divided by (ii) the share value
for the Company Stock
Fund
of
the
CPSP
on the
applicable Allocation
Date.
This
amount
shall be
credited no
later
than
the
end
of
the
month
following
the
Valuation
Date
that
the
Semiannual
Allocation
or
Supplemental
Allocation
to
the
Company
Stock
Fund
would
have
been
made
had
the
Participant
received
a
Semiannual
Allocation
or
Supplemental
Allocation
under
the
Stock
Savings
Feature.
A
share
in
the
Company
Stock
Fund
of
the
Supplemental Stock
Savings Feature
Account shall
have a
value equivalent
to a
share in
the Company Stock Fund of the CPSP.
Exhibit 10.11.1
9
Section 4.1
Supplemental Stock Savings Account Feature Earnings
After
being
initially
invested
in
the
Company
Stock
Fund
account,
the
amounts
in
the
Participant’s
Supplemental Stock
Savings Feature
Account shall
thereafter be
eligible to
be
invested
in
the
same
investment
funds
as
are
made
available
to
Participants
in
the
CPSP from time to
time.
While such investments shall
consist solely of book
entries and
shall not
actually be
invested
in such
funds, the
book entry
share value
of
such deemed
investment funds in this
Plan shall be determined
to be the same share
value as the actual
value
of
shares
in
the
investment
funds
of
the
CPSP.
The
amounts
deemed invested
in
this
Plan
shall be
valued
at
the
same
time
and
in the
same
manner as
though
they
were
actually
invested
in
the
CPSP.
Also,
deemed
investments
in
the
Participant’s
Supplemental
Stock
Savings
Feature
Account
may
be
exchanged
into
other
available
investment
funds
in
the
same
manner,
at
the
same
times,
and
subject
to
the
same
limitations as though the deemed amounts
were actually invested in the
CPSP.
However,
to the
extent that
earnings in
the form
of dividends
on Company
Stock in
the CPSP
are
eligible
to
be
passed
through
to
the
Participant,
such
dividends
will
be
deemed
to
have
been reinvested
in the
Company
Stock Fund
of
this
Plan, without
regard to
whether the
Participant has made a pass through election under the CPSP.
Section 5.
Payment.
If
a
Participant
terminates
employment
with
the
Affiliated
Group
for
any
reason
except
death, Disability,
Layoff during
or after the
year in
which the Participant
reaches age 50,
or
Retirement,
Benefits
which
the
Participant
is
eligible
to
receive
under
this
Plan
shall
be
paid
in
one
lump
sum
cash
payment
as
soon
as
practicable
following
his
or
her
termination.
If
a
Participant
dies
prior
to
Retirement,
Benefits
which
the
Participant
is
eligible
to
receive
under
this
Plan
shall
be
paid
in
one
lump
sum
cash
payment
to
the
Participant's
Beneficiary
as
soon
as
practicable
after
his
or
her
death.
If
a
Participant
Retires,
is
Laid
off
during
or
after
the
year
in
which
the
Participant
reaches
age
50,
or
becomes
Disabled,
Benefits
which
the
Participant
is
eligible
to
receive
under
this
Plan
shall
be
paid
in
one
lump
sum
cash
payment
as
soon
as
practicable
following
the
Participant's
Retirement,
Layoff,
determination
of
Disability,
or
termination
of
Exhibit 10.11.1
10
employment; provided
that such
a Participant
may
indicate a
preference
to defer
part
or
all of such lump sum cash payment under the terms of the KEDCP.
All lump
sum cash
payments shall
be made
only as
of a
Valuation
Date and
shall be
net
of withholding for applicable taxes required by law.
The Chief
Executive Officer
of ConocoPhillips,
with respect
to Participants
who are
not
subject
to
section
16
of
the
Exchange
Act,
and
the
Committee,
with
respect
to
Participants
who
are
subject
to
section
16
of
the
Exchange
Act,
shall
consider
such
indication of
preference and
shall respectively
decide in
the Chief
Executive Officer's
or
the Committee's
sole discretion
whether to
accept or
reject the
preference expressed.
In
the
event
the
Chief
Executive
Officer
or
the
Committee,
as
applicable,
accepts
such
Participant's
preference,
the
Participant's
Benefit
from
this
Plan
shall
be
credited
as
an
Award
under
the
KEDCP
as
soon
as
practicable
after
the
Participant's
Retirement,
Layoff, or the date the Participant is determined to be Disabled.
Section 5.1
Beneficiary Designation.
A Participant
may
designate
a
Beneficiary
or
Beneficiaries
to receive
the
entire
balance
of
the
Participant’s
Deferred
Compensation
Account
by
giving
signed
written
notice
of
such designation
to the
Plan Administrator
upon forms
supplied by
and delivered
to the
Plan
Administrator
and
may
revoke
such
designations
in
writing;
provided,
that
writing
and
signing
may
be
done
by
any
electronic
means
approved
by
the
Plan
Administrator.
The
Participant
may
from
time
to
time
change
or
cancel
any
previous
beneficiary
designation
in
the
same
manner.
The
last
beneficiary
designation
received
by
the
Plan
Administrator shall
be controlling
over any
prior
designation and
over any
testamentary
or
other
disposition.
After
acceptance
by
the
Plan
Administrator
of
such
written
designation, it
shall take
effect as
of the
date on
which it
was signed
by the
Participant,
whether the
Participant is
living at
the time
of such
receipt, but
without prejudice
to the
Company
or
any
member
of
the
Controlled
Group
or
the
Plan
Administrator
or
their
respective employees and
agents on account of
any payment made
under this Plan
before
receipt
of
such
designation.
If
no
designation
of
a
Beneficiary
is
on
file
with
the
Plan
Exhibit 10.11.1
11
Administrator
at
the
time
of
the
death
of
the
Participant
or
such
designation
is
not
effective
for
any
reason
as
determined
by
the
Plan
Administrator,
then,
for
purposes
of
this
Plan,
“Beneficiary”
shall
mean,
and
such
Benefits
shall
be
paid
to,
(i)
the
Participant's
surviving
spouse
as
of
the
Participant's
date
of
death,
or
(ii)
if
there
is
no
surviving spouse as of the Participant's date of death, the Participant’s estate.
Section 6.
Nonassignability.
The
interest
of
a
Participant
or
his
Beneficiary
or
Beneficiaries
hereunder
may
not
be
sold,
transferred,
assigned,
or
encumbered
in
any
manner,
either
voluntarily
or
involuntarily,
and
any
attempt
so
to
anticipate,
alienate,
sell,
transfer,
assign,
pledge,
encumber, or
charge the
same shall be null
and void; neither
shall the Benefits
hereunder
be
liable
for
or
subject
to
the
debts,
contracts,
liabilities,
engagements,
or
torts
of
any
person
to
whom
such
Benefits
or
funds
are
payable,
nor
shall
they
be
an
asset
in
bankruptcy or subject to garnishment, attachment, or other legal or equitable proceedings.
Section 7.
Administration.
(a)
The Plan shall be administered by the Plan Administrator.
The Plan Administrator
may
delegate
to
employees
of
the
Company
or
any
Affiliated
Company
the
authority
to
execute
and
deliver
such
instruments
and
documents,
to
do
all
such
acts
and
things,
and
to
take
such
other
steps
deemed
necessary,
advisable,
or
convenient
for
the
effective
administration
of
the
Plan
in
accordance
with
its
terms
and
purpose,
except
that
the
Plan
Administrator
may
not
delegate
any
discretionary
authority
with
respect
to
substantive
decisions
or
functions
regarding
the
Plan
or
Benefits
under
the
Plan.
The
Plan
Administrator
may
designate
a
third
party
to
provide
services
that
may
include
record
keeping,
Participant accounting, Participant communication, payment of
installments to the
Participant,
tax
reporting,
and
any
other
services
specified
in
an
agreement
with
such third
party.
The Plan
Administrator may
adopt such
rules, regulations,
and
forms
as
deemed
desirable
for
administration
of
the
Plan
and
shall
have
the
discretionary
authority
to
allocate
responsibilities
under
the
Plan
to
such
other
Exhibit 10.11.1
12
persons
as
may
be
designated.
The
Plan
Administrator
shall
have
absolute
discretion
in
carrying
out
its
responsibilities,
and
all
interpretations,
findings
of
fact
and
resolutions
described
herein
which
are
made
by
the
Plan
Administrator
shall be binding, final and conclusive on all parties.
The Plan
Administrator
and his
or her
delegates shall
serve without
bond
and without
compensation for
services under
this Plan.
All expenses
of the
Plan
Administrator and his or her delegates for services under this Plan shall be paid by
the
Company.
None
of
the
Plan
Administrator
or
his
or
her
delegates
shall
be
liable
for
any
act
or
omission
on
his
or
her
own
part
excepting
his
or
her
own
willful
misconduct.
Without
limiting
the
generality
of
the
foregoing,
any
such
decision
or
action
taken
by
the
Plan
Administrator
or
his
or
her
delegates
in
reliance
upon
any
information
supplied
by
an
officer
of
the
Company,
the
Company's
legal
counsel,
or
the
Company's
independent
accountants
in
connection
with
the
administration
of
this
Plan
shall
be
deemed
to
have
been
taken in good faith.
(b)
Any
claim
for
benefits
hereunder
shall
be
presented
in
writing
to
the
Plan
Administrator
for
consideration,
grant,
or
denial.
In
the
event
that
a
claim
is
denied in
whole or
in part
by the
Plan Administrator,
the claimant,
within ninety
days
of
receipt
of
said
claim
by
the
Plan
Administrator,
shall
receive
written
notice of denial.
Such notice shall contain:
(1)
A statement of the specific reason or reasons for the denial;
(2)
Specific
references
to
the
pertinent
provisions
hereunder
on
which
such
denial is based;
(3)
A
description
of
any
additional
material
or
information
necessary
to
perfect the
claim and
an explanation
of why
such material
or information
is necessary; and
(4)
An
explanation
of
the
following
claims
review
procedure
set
forth
in
paragraph (c) below.
(c)
Any claimant
who
feels that
a claim
has been
improperly
denied
in whole
or in
part
by
the
Plan
Administrator
may
request
a
review
of
the
denial
by
making
written application to
the Trustee.
The claimant shall
have the right
to review
all
pertinent
documents
relating
to
the
claim
and
to
submit
issues
and
comments
in
Exhibit 10.11.1
13
writing
to
the
Trustee.
Any
person
filing
an
appeal
from
the
denial
of
a
claim
must
do
so
in
writing
within
sixty
days
after
receipt
of
written
notice
of
denial.
The
Trustee
shall
render
a
decision
regarding
the
claim
within
sixty
days
after
receipt of
a request
for review,
unless special
circumstances require
an extension
of
time
for
processing,
in
which
case
a
decision
shall
be
rendered
within
a
reasonable time, but not later than 120
days after receipt of the request for
review.
The decision
of the
Trustee
shall be
in writing
and, in
the case
of the
denial of
a
claim in whole
or in part,
shall set forth
the same
information as is
required in an
initial notice of denial by the Plan
Administrator, other than an
explanation of this
claims
review procedure.
The
Trustee
shall
have absolute
discretion
in
carrying
out its responsibilities to make
its decision of an appeal,
including the authority to
interpret and construe the terms hereunder, and all interpretations, findings of fact,
and the decision of the Trustee
regarding the appeal shall be final, conclusive,
and
binding on all parties.
(d)
Compliance
with
the
procedures
described
in
paragraphs
(b)
and
(c)
shall
be
a
condition precedent to the filing of any
action to obtain any benefit or
enforce any
right
that
any
individual
may
claim
hereunder.
Notwithstanding
anything
to
the
contrary
in
this
Plan,
these
paragraphs
(b),
(c)
and
(d)
may
not
be
amended
without
the
written
consent
of
a
seventy-five
percent
(75%)
majority
of
Participants
and
Beneficiaries
and
such
paragraphs
shall
survive
the
termination
of this Plan until all benefits accrued hereunder have been paid.
Section 8.
Rights of Employees and Participants.
Nothing
contained in
the
Plan
(or
in
any
other
documents
related
to
this
Plan
or
to
any
Benefit)
shall
confer
upon
any
Employee
or
Participant
any
right
to
continue
in
the
employ
or
other
service
of
the
Company
or
any
member
of
the
Affiliated
Group
or
constitute
any
contract or
limit
in any
way
the
right
of
the
Company
or
any
member
of
the Affiliat
ed
Group to
change such
person's
compensation
or other
benefits
or position
or to terminate the employment of such person with or without cause.
Exhibit 10.11.1
14
Section 9.
Awards in Foreign
Countries.
The
Board
or
its
delegate
shall
have
the
authority
to
adopt
such
modifications,
procedures, and
subplans as
may be
necessary or
desirable to
comply with
provisions of
the
laws
of
foreign
countries
in
which
the
Company
or
Participating
Subsidiaries
may
operate to
assure the
viability of
the Benefits
of Participants
employed in
such countries
and to meet the purpose of this Plan.
Section 10.
Amendment and Termination.
The Board reserves
the right
to amend this
Plan from time
to time,
to terminate this
Plan
entirely
at
any
time,
and
to
delegate
such
authority
as
the
Board
deems
necessary
or
desirable;
provided,
however,
that
no
amendment
may
affect
the
balance
in
a
Participant’s
account
on
the
effective
date
of
the
amendment;
and
further
provided,
the
Company shall remain
liable for any
Benefits accrued under
this Plan prior
to the date
of
amendment or termination.
Section 11.
Method of Providing Payments.
(a)
Nonsegregation.
Amounts
deferred
pursuant
to
this
Plan
and
the
crediting
of
amounts to
a Participant’s
accounts shall
represent
the Company’s
unfunded and
unsecured
promise
to
pay
compensation
in
the
future.
With
respect
to
said
amounts, the relationship of
the Company and a
Participant shall be that
of debtor
and
general
unsecured
creditor.
While
the
Company
may
make
investments
for
the
purpose
of
measuring
and
meeting
its
obligations
under
this
Plan
such
investments shall remain the sole property of the
Company subject to claims of its
creditors generally,
and shall
not be deemed
to form or
be included in
any part of
the Participant’s accounts.
(b)
Funding.
It is
the intention
of the
Company that
this
Plan shall
be unfunded
for
federal tax
purposes and
for purposes
of Title
I of
ERISA.
All amounts
payable
under this
Plan
shall
be paid
solely
from
the
general assets
of
the
Company
and
Exhibit 10.11.1
15
any
rights
accruing
to
a
Participant
under
this
Plan
shall
be
those
of
a
general
creditor; provided, however,
that the Company
may establish one
or more grantor
trusts to
satisfy part
or all
of the
Company's Plan
payment obligations
so long
as
this
Plan
remains
unfunded
for
purposes
of
sections
201(2),
301(a)(3),
and
401(a)(1) of ERISA.
Section 12.
Miscellaneous Provisions.
(a)
Except
as
otherwise
provided
herein,
the
Plan
shall
be
binding
upon
the
Company,
its successors and
assigns, including but
not limited to
any corporation
which may acquire all or
substantially all of the Company's
assets and business or
with or into which the Company may be consolidated or merged.
(b)
This Plan
shall be
construed, regulated,
and administered
in accordance
with
the
laws of the State of Texas
except to the extent that said laws have been preempted
by
the
laws
of
the
United
States.
The
forum
and
venue
for
any
suit
brought
regarding any claim under this Plan shall be in Harris County, Texas.
(c)
If
any
provision
of
this
Plan
shall
be
held
illegal
or
invalid
for
any
reason,
said
illegality
or
invalidity
shall
not
affect
the
remaining
provisions
hereof;
instead,
each
provision
shall
be
fully
severable,
and
this
Plan
shall
be
construed
and
enforced as if said illegal or invalid provision had never been included herein.
(d)
For
purposes
of
this
Plan,
electronic
communications
and
signatures
shall
be
considered to be
in writing if
made in conformity
with procedures which
the Plan
Administrator may adopt from time to time.
(e)
The
Plan
Administrator,
in
its
sole
discretion,
may
direct
that
a
payment
to
be
made
to
an
incompetent
or
disabled
person,
whether
because
of
minority
or
mental
or
physical
disability,
instead
be
made
to
the
guardian
or
legal
representative
of
such
person
or
to
the
person
having
custody
of
such
person
(unless prior
claim therefor
shall have
been made
by a
duly qualified
guardian or
other
legal
representative),
without
further
liability
either
on
the
part
of
the
Company
or
a
Participating
Subsidiary
or
the
Plan
for
the
amount
of
such
payment
to
the
person
on
whose
benefit
such
payment
is
made.
Any
payment
made
in
accordance
with
the
provisions
of
this
provision
shall
be
a
complete
Exhibit 10.11.1
16
discharge
of
any
liability
of
the
Company,
its
Subsidiaries,
and
this
Plan
with
respect to the Benefits so paid.
(f)
Payment
of
Plan
Benefits
may
be
subject
to
administrative
or
other
delays
that
result
in
payment
to
the
Participant
or
his
beneficiaries
on
a
date
later
than
the
date
specified
in
this
Plan
or
the
Participant's
Election
Form.
No
Participant
or
Beneficiary
shall
be
entitled
to
any
additional
earnings
or
interest
in
respect
of
any such payment delays, nor shall any Participant or Beneficiary be provided any
election with respect to the timing of any delayed payment.
(g)
If
all
or
any
part
of
any
Participant's
or
Beneficiary's
Benefit
hereunder
shall
become subject to any estate, inheritance, income, employment
or other tax which
the
Company
shall
be
required
to
pay
or
withhold,
the
Company
shall
have
the
full power
and authority
to withhold
and pay
such tax
out of
any monies
or other
property
held
for
the
account
of
the
Participant
or
Beneficiary
whose
interests
hereunder
are
so
affected
(including,
without
limitation,
by
reducing
and
offsetting the Participant's or
Beneficiary's account balance).
Prior to making any
payment,
the
Company
may
require
such
releases
or
other
documents
from
any
lawful taxing authority as it shall deem necessary or desirable.
(h)
No
amount
accrued
or
payable
hereunder
shall
be
deemed
to
be
a
portion
of
an
Employee's
compensation
or
earnings
for
the
purpose
of
any
other
employee
benefit
plan
adopted
or
maintained
by
the
Company,
nor
shall
this
Plan
be
deemed to amend or modify the provisions of the CPSP.
(i)
It is
the intention
of the
Company that,
so long
as any
of ConocoPhillips’
equity
securities
are
registered
pursuant
to
section
12(b)
or
12(g)
of
the
Securities
Exchange Act
of 1934,
this Plan
shall be
operated in
compliance with
16(b) and,
if any Plan provision or transaction is found not to comply with
section 16(b), that
provision
or
transaction,
as
the
case
may
be,
shall
be
deemed
null
and
void
ab
initio
.
Notwithstanding anything
in the
Plan to
the contrary,
the Company,
in its
absolute discretion,
may bifurcate
the Plan
so as
to restrict,
limit or
condition the
use
of
any
provision
of
the
Plan
to
Participants
who
are
officers
and
directors
subject
to
section
16(b)
without
so
restricting,
limiting
or
conditioning
the
Plan
with respect to other Participants.
(j)
This Frozen Plan was frozen effective as
of December 31, 2004, and was replaced
Exhibit 10.11.1
17
by
the
Ongoing
Plan.
The
distribution
of
amounts
that
were
earned
and
vested
(within
the
meaning
of
Code
section
409A
and
official
guidance
issued
thereunder) under the Frozen Plan
prior to January 1,
2005 (and earnings thereon)
are
exempt
from
the
requirements
of
Code
section
409A
shall
be
made
in
accordance with the terms of the Frozen Plan.
(k)
This Plan
was previously
restated and
amended on
December 29,
2005, effective
as
of
January
1,
2005.
Effective
at
that
time,
this
Plan
assumed
the
Other
Obligations
and
any
other
obligations,
claims,
benefits,
rights,
and
duties
as
set
forth
in
the
Amendment
to
and
Merger
of
Amended
and
Restated
Conoco
Inc.
Salary
Deferral
&
Savings
Restoration
Plan
into
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips
and
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips,
pursuant
to
which
a
portion
of
the
Amended
and
Restated
Conoco
Inc.
Salary
Deferral
&
Savings
Restoration
Plan
was
merged
into
this
Plan
effective
October
3,
2003.
Such
Other
Obligations
shall
be
deemed
to
be
part
of
the
Supplemental
Thrift
Benefit
Feature
account
of
each
affected
Participant
and
book
entries
made
in
accordance
with
the
investment
directions
for each affected Participant at such time.
(l)
At the Effective
Time, certain
active employees of
Phillips 66 and
members of its
controlled
group
ceased
to
participate
in
the
Plan,
and
the
liabilities,
including
liabilities related to
benefits grandfathered from Code
section 409A (
i.e.
, amounts
deferred
and
vested
prior
to
January
1,
2005),
for
these
participant's
benefits
under the Plan were transferred to the members of the Phillips 66 controlled group
and
continued
as
the
Phillips
66
Defined
Contribution
Make-Up
Plan.
ConocoPhillips
distributed its
interest
in
Phillips
66
to
its
shareholders
as
of
the
Distribution.
Notwithstanding Section
10 of
this Plan,
on and
after the
Effective
Time,
the Company,
ConocoPhillips, other
members of
the Controlled
Group (as
determined after
the Distribution),
the Plan,
any directors,
officers,
or employees
of
any
member
of
the
Controlled
Group
(as
determined
after
the
Distribution),
and
any
successors
thereto,
shall
have
no
further
obligation
or
liability
to,
or
on
behalf
of,
any
such
participant
with
respect
to
any
benefit,
amount,
or
right
transferred to or due under the Phillips 66 Defined Contribution Make-Up Plan.
Further, as of the
Distribution, any Phillips 66 common
stock ("Phillips 66
Exhibit 10.11.1
18
Stock")
held
in
the
Company
Stock
Fund
shall
be
transferred
to
a
separate
Investment
Option
under
this
Plan
that
is
accounted
for
as
if
investments
were
made
in
Phillips
66
Stock,
although
no
such
actual
investments
need
be
made,
with
accounting
entries
being
sufficient
therefor.
Investments
in
the
Phillips
66
Stock
fund
will
be
determined
as
of
the
Distribution.
On
and
after
the
Distribution, a
Participant will
be allowed
to hold
or liquidate
his or
her deemed
investment in Phillips
66 Stock.
No additional deemed investments
in Phillips 66
Stock will be allowed to be elected.
Section 13.
Effective Date of the Restated Plan.
Title
I of
the Defined
Contribution Make-Up
Plan of
ConocoPhillips is
hereby amended
and restated as set forth in
this 2020 Amendment and Restatement
effective as of January
1, 2020.
Executed this ____ day of December 2019, by a duly authorized officer of the Company.
______________________________
Heather G. Sirdashney
Vice President, Human Resources
DCMP Title I 2020 Restatement
12-19-2019
EX-10.11.2
Exhibit 10.11.2
1
DEFINED CONTRIBUTION MAKE-UP PLAN
OF
CONOCOPHILLIPS
TITLE II
(Effective for benefits earned or vested after
December 31, 2004)
2020 AMENDMENT AND RESTATEMENT
The
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips,
Title
II
(the
“Ongoing
Plan”),
is
hereby
amended
and
restated
effective
as
of
January
1,
2020
(except
where
another date is specified herein with regard to a particular provision).
Immediately
prior
to
effectiveness
of
this
2020
Amendment
and
Restatement,
the
Ongoing
Plan
was
and
remains
subject
to
the
2012
Restatement
of
the
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips,
Title
II,
which
was
effective
as
of
the
"Effective
Time"
defined
in
the
Employee
Matters
Agreement
by
and
between
ConocoPhillips
and
Phillips
66
(the
"Effective
Time"),
together
with
the
First
Amendment
to
Title
II
of
the
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips
(2012 Restatement),
effective January
1, 2013,
the Second
Amendment to
Title
II of
the
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips
(2012
Restatement),
effective
January 1, 2016, and the
Third Amendment to Title
II of the Defined Contribution
Make-
Up Plan of ConocoPhillips (2012 Restatement), effective October 30, 2019.
Preamble
The purpose of this Plan is to attract and retain key
employees by providing supplemental
benefits for those Eligible Employees
whose benefits under the CPSP
might otherwise be
affected
by
Pay
Limitations
or
by
a
voluntary
reduction
in
salary
under
provisions
of
KEDCP.
The Defined Contribution Make-Up Plan of ConocoPhillips is intended to provide certain
specified
benefits
to
Eligible
Employees
whose
benefits
under
the
ConocoPhillips
Exhibit 10.11.2
2
Savings Plan might otherwise be limited.
Title I of the
Plan, sometimes referred to as
the
Frozen
Plan,
is
effective
with
regard
to
benefits
earned
and
vested
prior
to
January
1,
2005, while
Title
II of
the
Plan,
sometimes referred
to as
the Ongoing
Plan,
is effective
with regard
to benefits
earned or
vested
after December
31, 2004.
Earnings,
gains, and
losses
shall
be
allocated
to
the
Title
of
the
Plan
to
which
the
underlying
obligations
giving rise to them are allocated.
The Ongoing
Plan is
intended (1)
to comply
with Code
section 409A,
as enacted
as part
of the
American Jobs
Creation Act
of 2004,
and official
guidance issued
thereunder,
and
(2) to
be “a
plan which
is unfunded
and is
maintained by
an employer
primarily
for the
purpose of
providing deferred
compensation for
a select
group of
management or
highly
compensated employees” within the meaning of sections
201(2), 301(a)(3), and 401(a)(1)
of ERISA.
Notwithstanding any other provision
of this Ongoing Plan,
this Ongoing Plan
shall
be
interpreted,
operated,
and
administered
in
a
manner
consistent
with
these
intentions.
Section 1.
Definitions.
For
purposes
of
the
Plan,
the
following
terms,
as
used
herein,
shall
have
the
meaning
specified:
(a)
“Allocation
Ratio”
shall
mean
the
ratio
determined
by
dividing
(i)
an
amount
equal
to
the
total
value
of
the
unallocated
shares
of
Stock
allocated
to
Stock
Savings
Feature
participants
and
beneficiaries
as
of
a
Stock
Savings
Feature
Semiannual
Allocation
Date
or
Supplemental
Allocation
Date
(as
defined
in
the
CPSP)
by
(ii)
an
amount
equal
to
the
total
net
Stock
Savings
Feature
employee
deposits
used
in
the
calculation
of
the
Stock
Savings
Feature
Semiannual
Allocation or Supplemental Allocation (as defined in the CPSP).
(b)
“Beneficiary”
shall
mean
a
person
or
persons
or
the
trustee
of
a
trust
for
the
benefit
of
a
person
designated
by
a
Participant
to
receive,
in
the
event
of
death,
any
unpaid
portion
of
a
Participant's
Benefits
from
this
Plan,
as
provided
in
Section 5.3.
Exhibit 10.11.2
3
(c)
“Benefit”
shall
mean
an
obligation
of
the
Company
to
pay
amounts
from
the
Ongoing Plan.
(d)
“Board”
shall
mean
the
Board
of
Directors
of
the
Company,
as
it
may
be
comprised from time to time.
(e)
“Code”
shall mean the
Internal Revenue Code
of 1986,
as amended from
time to
time, or any successor statute.
(f)
“Committee”
shall mean the Nonqualified Plans Benefit
Committee as appointed
from
time
to
time
by
the
Board;
provided,
however,
that
until
a
successor
is
appointed by
the Board,
the individual
serving as
the Company’s
Vice
President
with responsibility over human resources shall be sole member of the Committee.
(g)
“Company”
shall
mean
ConocoPhillips
Company,
a
Delaware
corporation,
or
any successor corporation.
The Company is a subsidiary of ConocoPhillips.
(h)
“Company Stock Fund”
shall mean an Investment
Option under this Plan
that is
accounted for as if
investments were made
in the common
stock, $0.01 par
value,
of
ConocoPhillips,
although
no
such
actual
investments
need
be
made,
with
accounting entries being sufficient therefor.
(i)
“ConocoPhillips”
shall
mean
ConocoPhillips,
a
Delaware
corporation,
or
any
successor
corporation.
ConocoPhillips
is
a
publicly
held
corporation
and
the
parent of the Company.
(j)
“Controlled Group”
shall mean ConocoPhillips and its Subsidiaries.
(k)
“CPSP”
shall mean the ConocoPhillips Savings Plan.
(l)
“CPSP Pay”
shall mean
"
Pay
"
as defined in the CPSP.
(m)
“DCMP
Pay”
shall
mean
"
Pay
"
as
defined
in
the
CPSP
without
regard
to
Pay
Limitations or voluntary salary reduction under provisions of the KEDCP.
(n)
“Election
Form”
shall mean
a
written
form,
including
one
in
electronic
format,
provided by
the Plan
Administrator pursuant
to which
a Participant
may elect
the
time and form of payment of his or her Benefits.
(o)
“Eligible
Employee”
shall
mean
an
Employee
whose
DCMP
Pay
exceeds
the
amount
set
forth
in
Code
section 401(a)(17),
as
amended
from
time
to
time,
or
who
is
eligible
to
elect
a
voluntary
salary
reduction
under
the
provisions
of
the
KEDCP.
(p)
“Employee”
shall
mean
any
individual
who
is
a
salaried
employee
of
the
Exhibit 10.11.2
4
Company or any Participating Subsidiary.
(q)
“Employer Discretionary
Account”
shall have
the same
meaning as
set forth
in
the CPSP.
(r)
“Employer Discretionary
Contribution Account”
shall have the
same meaning
as set forth in the CPSP.
(s)
“Employer Matching
Account”
shall have
the same
meaning as
set forth
in the
CPSP.
(t)
“Employer
Matching
Contribution
Account”
shall
have
the
same
meaning
as
set forth in the CPSP.
(u)
“ERISA”
shall mean
the Employee
Retirement Income
Security Act
of 1974,
as
amended from time to time, or any successor statute.
(v)
“Frozen
Plan”
shall mean
Title
I of
the Defined
Contribution
Make-Up Plan
of
ConocoPhillips.
(w)
“Investment
Options”
shall
mean
the
investment
options,
as
determined
from
time to
time by
the Plan
Administrator,
used to
credit earnings,
gains, and
losses
on Supplemental Thrift Feature Account and
Supplemental Stock Savings Feature
Account balances.
(x)
“KEDCP”
shall
mean
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips
or
any
similar
or
successor
plan
maintained
by
a
member
of
the
Controlled Group.
(y)
“Ongoing
Plan”
shall mean
Title
II
of
the
Defined
Contribution
Make-Up
Plan
of ConocoPhillips.
(z)
“Participant”
shall
mean
an
Eligible
Employee
who
is
eligible
to
receive
a
Benefit from
this
Plan as
a result
of being
an Eligible
Employee and
any
person
for
whom
a
Supplemental
Thrift
Feature
Account
and/or
a
Supplemental
Stock
Savings Feature Account is maintained.
(aa)
“Participating Subsidiary”
shall mean a Subsidiary which has adopted the CPSP
and of which one
or more Employees are
Participants eligible to make
deposits to
the CPSP or are eligible for Benefits pursuant to this Plan.
(bb)
“Pay
Limitations”
shall
mean
the
compensation
limitations
applicable
to
the
CPSP that are set forth in Code section 401(a)(17), as adjusted.
(cc)
“Plan”
shall
mean
the
Defined
Contribution
Make-Up
Plan
of
ConocoPhillips.
Exhibit 10.11.2
5
The Plan is sponsored and maintained by the Company.
(dd)
“Plan Administrator”
shall mean the Committee.
(ee)
“Plan Year
”
shall mean January 1 through December 31.
(ff)
“Separation
from
Service”
shall
mean
the
date
on
which
the
Participant
has
a
“separation
from
service,”
within
the
meaning
of
Code
section
409A(a)(2)(A)(i)
and
section
1.409A-1(h)
of
the
Treasury
regulations,
with
the
controlled
group,
whether
by
reason
of
death,
disability,
retirement,
or
otherwise.
In
determining
Separation from Service, with regard to
a bona fide leave of absence that
is due to
any
medically
determinable
physical
or
mental
impairment
that
can
be
expected
to result in death or can be expected to last for a continuous period of not less than
six months,
where such impairment
causes the Employee
to be unable
to perform
the
duties
of
his
or
her
position
of
employment
or
any
substantially
similar
position
of
employment,
a
twenty-nine
(29)-month
period
of
absence
shall
be
substituted
for
the
six
(6)-month
period
set
forth
in
section
1.409A-1(h)(1)(i)
of
the Treasury regulations, as allowed thereunder.
(gg)
“Stock”
shall
mean
shares
of
common
stock,
$0.01
par
value,
issued
by
ConocoPhillips.
(hh)
“Stock Savings Feature”
shall mean the Stock Savings Feature of the CPSP.
(ii)
“Subsidiary”
shall mean any corporation
or other entity that
is treated as a
single
employer with
ConocoPhillips under
section 414(b)
, (c),
or (m)
of the
Code.
In
applying section
1563(a)(1), (2),
and (3)
of the
Code for
purposes of
determining
a
controlled
group
of
corporations
under
section
414(b)
and
for
purposes
of
determining
trades
or
businesses
(whether
or
not
incorporated)
under
common
control
under
regulation
section
1.414(c)-2
for
purposes
of
Code
section
414(c),
the
language
“at
least
80%”
shall
be
used
without
substitution
as
allowed
under
regulations pursuant to Code section 409A.
(jj)
“Supplemental
Stock
Savings
Contributions”
shall
mean
an
amount
equal
to
1% of the amount of
the Participant’s
DCMP Pay for a Plan
Year
that is in excess
of the Participant’s CPSP Pay for such Plan Year.
(kk)
“Supplemental
Stock
Savings
Feature
Account”
shall
mean
the
Plan
Benefit
account
of
a
Participant
that
reflects
the
portion
of
his
or
her
Benefit
that
is
intended to replace certain Stock Savings Feature benefits to which the Participant
Exhibit 10.11.2
6
might otherwise be entitled
but for the application
of the Pay Limitations
and/or a
voluntary salary reduction under the KEDCP.
(ll)
“Supplemental Thrift
Contributions”
shall mean
an amount
equal to
1.25% of
the amount of the
Participant’s DCMP
Pay for a Plan
Year
that is in excess
of the
Participant’s CPSP Pay for such Plan Year.
(mm)
“Supplemental Thrift Feature Account”
shall mean the Plan Benefit
account of
a Participant
which reflects
the portion
of his
or her
Benefit which
is intended
to
replace certain Thrift Feature benefits
to which the Participant
might otherwise be
entitled
but
for
the
application
of
the
Pay
Limitations
and/or
a
voluntary
salary
reduction under the KEDCP.
(nn)
“Thrift Feature”
shall mean the Thrift Feature of the CPSP.
(oo)
“Trustee”
shall mean the trustee of
the grantor trust established
for this Plan by a
trust agreement between the Company and the trustee, or any successor trustee.
(pp)
“Valuation
Date”
shall mean “Valuation
Date” as defined in the CPSP.
Section 2.
Eligibility.
Benefits may only be granted to Eligible Employees.
Section 3.
Supplemental Thrift Feature Account Benefits.
For
any
period
in
which
an
Eligible
Employee’s
DCMP
Pay
exceeds
his
or
her
CPSP
Pay,
a
Benefit
amount
shall
be
credited
to
an
Eligible
Employee’s
Supplemental
Thrift
Feature Account
for
the
Ongoing
Plan
no
later
than the
end
of
the
month
following
the
Valuation
Date
that
Company
contributions
are
made
either
to
the
Eligible
Employee’s
Employer
Matching
Contribution
Account
or
to
the
Eligible
Employee’s
Employer
Discretionary Contribution
Account, or
would have
been made
to either
such
account if
the
Eligible
Employee
had
received
Company
contributions
under
the
CPSP.
The
Benefit amount
so credited
shall equal
the percentage
set by
the CPSP
with regard
to an
Employer
Matching
Contribution
or
by
the
Company
with
regard
to
an
Employer
Discretionary
Contribution,
as
the
case
may
be,
multiplied
by
the
amount
by
which
the
Eligible
Employee’s
DCMP
Pay
for
the
period
for
which
the
Employer
Matching
Exhibit 10.11.2
7
Contribution or the Employer Discretionary Contribution, as the case may be, exceeds his
or her CPSP Pay for that period.
Section 3.1
Supplemental Thrift Feature Account Earnings
The
Company
shall
periodically
credit
earnings,
gains,
and
losses
to
a
Participant’s
Supplemental
Thrift
Feature
Account,
until
the
full
balance
of
such
Account
has
been
distributed.
Earnings, gains,
and losses
shall be
credited to
a Participant’s
Supplemental
Thrift
Feature
Account
under
this
Section
based
on
the
results
that
would
have
been
achieved had amounts credited to such Account been
invested as soon as practicable after
crediting
into
Investment
Options
selected
by
the
Participant.
The
Plan
Administrator
shall
specify
procedures
to
allow
Participants
to
make
elections
as
to
the
deemed
investment of
amounts newly
credited to
their Supplemental
Thrift Feature
Accounts, as
well
as
the
deemed
investment
of
amounts
previously
credited
to
their
Supplemental
Thrift Feature
Accounts.
Nothing in
this Section
or otherwise
in the
Plan, however,
will
require
the
Company
to
actually
invest
any
amounts
in
such
Investment
Options
or
otherwise.
Section 4.
Supplemental Stock Savings Feature Account Benefits.
For
each
month
in
which
a
Semiannual
or
Supplemental
Allocation
(as
defined
in
the
CPSP) is
made to
a Eligible
Employee’s
Stock Savings
Feature Account,
or would
have
been
made
to
such
account
if
the
Eligible
Employee
had
received
a
Semiannual
or
Supplemental
Allocation,
a
Benefit
amount
shall be
credited to
his
or
her Supplemental
Stock Savings Feature Account.
The Benefit amount to
be credited shall be
calculated in
shares
in
the
Company
Stock
Fund
of
this
Plan
and
shall
be
equal
to
(i)
the
Eligible
Employee's
Supplemental
Stock
Savings
Contributions
during
the
applicable Allocation
Period (as defined in the
CPSP) multiplied by the applicable Allocation
Ratio, divided by
(ii)
the
share
value
for
the
Company
Stock
Fund
of
the
CPSP
on
the
applicable
Allocation Date (as defined in
the CPSP).
This amount shall be credited no
later than the
end
of
the
month
following
the
Valuation
Date
that
a
Semiannual
Allocation
or
Supplemental
Allocation
is
made
under
the
Stock
Savings
Feature, or
would
have
been
Exhibit 10.11.2
8
made had the Eligible
Employee received such a
Semiannual Allocation or Supplemental
Allocation under the
Stock Savings Feature.
A share in
the Company Stock
Fund of this
Plan
shall
have
a
value
equivalent
to
a
share
in
the
Company
Stock
Fund
of
the
CPSP.
Notwithstanding the foregoing,
allocations under
this Section
4 shall
cease with
the final
allocation for the period ending December 31, 2012, made in January, 2013.
Section 4.1
Supplemental Stock Savings Feature Account Earnings
After
being
initially
invested
in
the
Company
Stock
Fund
account,
the
amounts
in
the
Participant’s
Supplemental Stock
Savings Feature
Account shall
thereafter be
eligible to
be
invested
in
Investment
Options
selected
by
the
Participant.
The
Company
shall
periodically
credit
earnings,
gains
and
losses
to
a
Participant’s
Supplemental
Stock
Savings
Feature
Account,
until
the
full
balance
of
such
Account
has
been
distributed.
Earnings,
gains,
and
losses
shall
be
credited
to
a
Participant’s
Supplemental
Stock
Savings
Feature
Account
under
this
Section
based
on
the
results
that
would
have
been
achieved had amounts credited to such Account been
invested as soon as practicable after
crediting into the Company Stock Fund of this Plan or the Investment Options selected by
the Participant.
The Plan
Administrator shall
specify procedures
to allow
Participants to
make
elections
as
to
the
deemed
investment
of
amounts
previously
credited
to
their
Supplemental
Stock
Savings Feature
Accounts.
Nothing
in
this
Section or
otherwise in
the Plan,
however,
will require
the Company
to actually
invest any
amounts in
Stock or
in such Investment Options or otherwise.
Section 5.
Payment.
In
the
absence
of
an
effective
election
under
Section
5.1
or
Section
5.2,
Benefits
that
a
Participant is
eligible to
receive under
the Ongoing
Plan (and
earnings, gains,
and losses
thereon) shall be
paid in
one lump sum
payment as of
the first calendar
quarter that is
(i)
with regard to elections
made before January 1,
2020, six (6)
months after the date
of the
Participant’s
Separation
from
Service
and
(ii)
with
regard
to
elections
made
after
December
31,
2019,
twelve
(12)
months
after
the
date
of
the
Participant’s
Separation
from Service.
Furthermore, in
the absence
of an
effective
election under
Section 5.1
or
Exhibit 10.11.2
9
Section 5.2, if
the Participant dies prior
to his or her
Separation from Service, or
after his
or
her
Separation
from
Service
but
prior
to
the
date
that
the
Benefits
which
the
Participant is
eligible to
receive under
the Ongoing
Plan (and
earnings, gains,
and losses
thereon)
commence
to
be
paid,
the
Benefits
that
the
Participant
is
eligible
to
receive
under
the
Ongoing
Plan
(and
earnings,
gains,
and
losses
thereon)
shall
be
paid
in
one
lump
sum
cash
payment
to
the
Participant’s
Beneficiary
or
Beneficiaries
as
soon
as
administratively practicable after the Participant’s death.
Section 5.1
Payment Election by Participant.
A Participant may elect on an Election Form delivered to the Plan
Administrator at a time
set by
the Plan
Administrator (which
shall be
prior to
the beginning
of the
Plan Year)
to
have the
amounts attributable
to Benefits
under the
Ongoing Plan
that are
credited to
his
or
her
Supplemental
Thrift
Feature
Account
(and
earnings,
gains,
and
losses
thereon)
with respect to
such Plan
Year
and the amounts
attributable to
Benefits credited to
his or
her
Supplemental
Stock
Savings
Feature
Account
(and
earnings,
gains,
and
losses
thereon) with respect to such Plan Year
paid to the Participant in either:
(a)
one lump sum payment, or
(b)
annual, semi-annual,
or quarterly
installments, using
a declining
balance method,
over a period ranging from one to fifteen years.
A Participant may
elect to have
payments commence as
of the beginning
of any calendar
quarter that is at least
one year after the date of
the Participant’s
Separation from Service,
provided
that,
for
elections
after
December
31,
2019,
no
first
payment
shall
commence
later than
the 100
th
birthday of
the Participant.
In the
absence of
an election
on the
date
which
a
payment
is
to
commence,
it
shall
commence
as
of
the
beginning
of
the
first
calendar quarter
that is
(i) with
regard to
elections made
before January
1, 2020,
six (6)
months after
the date
of the
Participant’s
Separation from
Service and
(ii) with
regard to
elections
made
after
December
31,
2019,
twelve
(12)
months
after
the
date
of
the
Participant’s Separation from Service.
Exhibit 10.11.2
10
Section 5.2
Change in Time or Form of Payment.
A Participant may
make an election
to change the
time or form
of payment elected under
Section 5.1 or the payment to be made under Section
5, but only if the following rules are
satisfied:
(a)
The
election
to
change
the
time
or
form
of
payment
may
not
take
effect
until
at
least twelve months after the date on which such election is made;
(b)
Except for
a payment
made with
respect to
the death
of the
Participant, payment
under such election
may not be
made earlier than
at least five
years from the
date
the payment would have otherwise been made or commenced;
(c)
Such payment may commence as of the beginning of any calendar quarter;
(d)
An
election
to
receive
payments
in
installments
shall
be
treated
as
a
single
payment for purposes of these rules;
(e)
The
election
may
not
result
in
an
impermissible
acceleration
of
payment
prohibited under Code section 409A;
(f)
No more than three (3) such elections shall be permitted; and
(g)
For changes made after December 31, 2019, no first payment may be scheduled to
commence after the 100
th
birthday of the Participant.
Section 5.3
Beneficiary Designation.
A Participant
may
designate
a
Beneficiary
or
Beneficiaries
to receive
the
entire
balance
of
the
Participant’s
Deferred
Compensation
Account
by
giving
signed
written
notice
of
such designation
to the
Plan Administrator
upon forms
supplied by
and delivered
to
the
Plan
Administrator
and
may
revoke
such
designations
in
writing;
provided,
that
writing
and
signing
may
be
done
by
any
electronic
means
approved
by
the
Plan
Administrator.
The
Participant
may
from
time
to
time
change
or
cancel
any
previous
beneficiary
designation
in
the
same
manner.
The
last
beneficiary
designation
received
by
the
Plan
Administrator shall
be controlling
over any
prior
designation and
over any
testamentary
or
other
disposition.
After
acceptance
by
the
Plan
Administrator
of
such
written
designation, it
shall take
effect as
of the
date on
which it
was signed
by the
Participant,
Exhibit 10.11.2
11
whether the
Participant is
living at
the time
of such
receipt, but
without prejudice
to the
Company
or
any
member
of
the
Controlled
Group
or
the
Plan
Administrator
or
their
respective employees and
agents on account of
any payment made
under this Plan
before
receipt
of
such
designation.
If
no
designation
of
a
Beneficiary
is
on
file
with
the
Plan
Administrator
at
the
time
of
the
death
of
the
Participant
or
such
designation
is
not
effective
for
any
reason
as
determined
by
the
Plan
Administrator,
then,
for
purposes
of
this
Plan,
“Beneficiary”
shall
mean,
and
such
Benefits
shall
be
paid
to,
(i)
the
Participant's
surviving
spouse
as
of
the
Participant's
date
of
death,
or
(ii)
if
there
is
no
surviving spouse as of the Participant's date of death, the Participant’s estate.
Section 5.4
Acceleration of Payment of Benefits.
Notwithstanding
any
other
provision
of
this
Plan
to
the
contrary,
except
as
provided
in
Section 12(g) and below,
in no event shall this
Plan permit the acceleration
of the time or
schedule
of
any
payment
or
distribution
under
this
Plan,
except
that
the
Plan
Administrator may
accelerate a payment
or distribution
under this
Plan to
comply with
a
certificate
of
divestiture,
as
provided
in
section
1.409A-3(j)(4)(iii)
of
the
Treasury
regulations.
Moreover,
if
a
portion
of
a
Participant's
Benefit
(and
earnings,
gains,
and
losses thereon)
is includible
in income
under Code
section 409A,
then such
portion shall
be
distributed
immediately
to
the
Participant
in
accordance
with
section
1.409A-
3(j)(4)(vii) of the Treasury regulations.
Section 6.
Nonassignability.
The
interest
of
a
Participant
or
his
Beneficiary
or
Beneficiaries
hereunder
may
not
be
sold,
transferred,
assigned,
or
encumbered
in
any
manner,
either
voluntarily
or
involuntarily,
and
any
attempt
so
to
anticipate,
alienate,
sell,
transfer,
assign,
pledge,
encumber, or
charge the
same shall be null
and void; neither
shall the Benefits
hereunder
be
liable
for
or
subject
to
the
debts,
contracts,
liabilities,
engagements,
or
torts
of
any
person
to
whom
such
Benefits
or
funds
are
payable,
nor
shall
they
be
an
asset
in
bankruptcy or subject to garnishment, attachment, or other legal or equitable proceedings.
Exhibit 10.11.2
12
Section 7.
Administration.
(a)
The
Plan
shall
be
administered
by
the
Plan
Administrator.
The
Plan
Administrator may
delegate to
employees of
the Company
or any
member of
the
Controlled
Group
the
authority
to
execute
and
deliver
such
instruments
and
documents,
to
do
all
such
acts
and
things,
and
to
take
such
other
steps
deemed
necessary,
advisable, or
convenient for
the effective
administration of
the Plan
in
accordance
with
its
terms
and
purpose,
except
that
the
Plan
Administrator
may
not
delegate
any
discretionary
authority
with
respect
to
substantive
decisions
or
functions regarding
the Plan
or Benefits
under the
Plan.
The Plan
Administrator
may designate
a third
party to
provide services
that
may include
record keeping,
Participant accounting, Participant communication, payment of installments
to the
Participant,
tax
reporting,
and
any
other
services
specified
in
an
agreement
with
such third
party.
The Plan
Administrator may
adopt such
rules, regulations,
and
forms
as
deemed
desirable
for
administration
of
the
Plan
and
shall
have
the
discretionary
authority
to
allocate
responsibilities
under
the
Plan
to
such
other
persons
as
may
be
designated.
The
Plan
Administrator
shall
have
absolute
discretion
in
carrying
out
its
responsibilities,
and
all
interpretations,
findings
of
fact
and
resolutions
described
herein
which
are
made
by
the
Plan
Administrator
shall be binding, final and conclusive on all parties.
(b)
The
Plan
Administrator
and
his
or
her
delegates
shall
serve
without
bond
and
without
compensation
for
services
under
this
Plan.
All
expenses
of
the
Plan
Administrator and his or her delegates for services under this Plan shall be paid by
the
Company.
None
of
the
Plan
Administrator
or
his
or
her
delegates
shall
be
liable
for
any
act
or
omission
on
his
or
her
own
part
excepting
his
or
her
own
willful
misconduct.
Without
limiting
the
generality
of
the
foregoing,
any
such
decision
or
action
taken
by
the
Plan
Administrator
or
his
or
her
delegates
in
reliance
upon
any
information
supplied
by
an
officer
of
the
Company,
the
Company's
legal
counsel,
or
the
Company's
independent
accountants
in
connection
with
the
administration
of
this
Plan
shall
be
deemed
to
have
been
taken in good faith.
Exhibit 10.11.2
13
Section 7.1
Claim for Benefits.
(a)
Any
claim
for
benefits
hereunder
shall
be
presented
in
writing
to
the
Plan
Administrator
for
consideration,
grant,
or
denial.
Claimants
will
be
notified
in
writing
of
approved
claims,
which
will
be
processed
as
claimed.
A
claim
is
considered
approved
only
if
its
approval
is
communicated
in
writing
to
a
claimant.
(b)
In the
case of
a denial
of a
claim respecting
benefits paid
or payable
with respect
to
a
Participant,
a
written
notice
will
be
furnished
to
the
claimant
within
ninety
(90) days of the date
on which the claim
is received by the
Plan Administrator.
If
special circumstances (such
as for a hearing)
require a longer period,
the claimant
will be notified in
writing, prior to the
expiration of the ninety
(90)-day period, of
the
reasons
for
an
extension
of
time;
provided,
however,
that
no
extensions
will
be permitted beyond ninety (90) days after the expiration of the initial ninety (90)-
day period.
A denial
or partial
denial of
a claim
will be
dated and
signed by
the
Plan Administrator and will clearly set forth:
(1)
the specific reason or reasons for the denial;
(2)
specific
reference
to
pertinent
Plan
provisions
on
which
the
denial
is
based;
(3)
a
description
of
any
additional
material
or
information
necessary
for
the
claimant to
perfect
the
claim
and an
explanation
of why
such
material
or
information is necessary; and
(4)
an
explanation
of
the
procedure
for
review
of
the
denied
or
partially
denied claim set forth below,
including the claimant’s
right to bring a civil
action
under
ERISA
section
502(a)
following
an
adverse
benefit
determination on review.
(c)
Upon
denial
of
a
claim,
in
whole
or
in
part,
a
claimant
or
his
duly
authorized
representative will
have the
right to
submit a
written request
to the
Trustee
for a
full and
fair
review of
the denied
claim by
filing
a written
notice
of
appeal
with
the Trustee
within sixty
(60) days
of the
receipt by
the claimant
of written
notice
of the denial
of the claim.
A claimant or
the claimant’s
authorized representative
Exhibit 10.11.2
14
will have, upon request and
free of charge, reasonable access
to, and copies of, all
documents,
records,
and
other
information
relevant
to
the
claimant’s
claim
for
benefits
and
may
submit
issues
and
comments
in
writing.
The
review
will
take
into
account all
comments,
documents,
records, and
other
information
submitted
by the
claimant relating
to the
claim, without
regard to
whether such
information
was
submitted
or
considered
in
the
initial
benefit
determination.
If the
claimant
fails to
file a
request for
review within
sixty
(60) days
of the
denial notification,
the claim
will be
deemed abandoned
and the
claimant precluded
from reasserting
it.
If
the
claimant
does
file
a
request
for
review,
his
request
must
include
a
description of
the issues
and evidence
he deems
relevant.
Failure to
raise issues
or present
evidence on
review will
preclude those
issues or
evidence from
being
presented in any subsequent proceeding or judicial review of the claim.
(d)
The
Trustee
will
provide
a
prompt
written
decision
on
review.
If
the
claim
is
denied on review, the decision shall set forth:
(1)
the specific reason or reasons for the adverse determination;
(2)
specific
reference
to
pertinent
Plan
provisions
on
which
the
adverse
determination is based;
(3)
a statement that the claimant is entitled to receive, upon request and free of
charge,
reasonable
access
to,
and
copies
of,
all
documents,
records,
and
other information relevant to the claimant’s claim for benefits; and
(4)
a
statement
describing
any
voluntary
appeal
procedures
offered
by
the
Plan
and
the
claimant’s
right
to
obtain
the
information
about
such
procedures, as well as a statement of the claimant’s
right to bring an action
under ERISA section 502(a).
(e)
A
decision
will
be
rendered
no
more
than
sixty
(60)
days
after
the
Trustee’s
receipt of
the request
for review,
except that
such period
may be
extended for
an
additional
sixty
(60)
days
if
the
Trustee
determines
that
special
circumstances
(such as for a hearing) require
such extension.
If an extension of time
is required,
written notice of
the extension
will be furnished
to the claimant
before the
end of
the initial sixty (60)-day period.
(f)
To
the extent permitted by
law, decisions
reached under the claims procedures
set
forth in
this
Section shall
be final
and
binding
on all
parties. No
legal action
for
Exhibit 10.11.2
15
benefits
under
the
Plan
shall
be
brought
unless
and
until
the
claimant
has
exhausted his
remedies under
this Section.
In any
such legal
action, the
claimant
may only
present evidence
and theories
which
the
claimant
presented during
the
claims
procedure.
Any
claims
which
the
claimant
does
not
in
good
faith
pursue
through
the
review
stage
of
the
procedure
shall
be
treated
as
having
been
irrevocably waived.
Judicial review
of a
claimant’s
denied claim
shall be
limited
to a
determination of
whether the
denial was
an abuse
of discretion
based on
the
evidence and theories the claimant presented during the claims procedure.
(g)
Any payment to a Participant or Beneficiary,
all in accordance with the provisions
of
this
Plan,
shall
to
the
extent
thereof
be
in
full
satisfaction
of
all
claims
hereunder
against
the
Plan
Administrator,
the
Company
and
all
Participating
Subsidiaries,
any
of
which
may
require
such
Participant
or
Beneficiary
as
a
condition to
such payment
to execute
a receipt
and
release therefor
in such
form
as shall be
determined by the
Plan Administrator,
the Company or
a Participating
Subsidiary.
If a
receipt and
release is
required and
the Participant
or Beneficiary
(as
applicable)
does
not
provide
such
receipt
and
release
in
a
timely
enough
manner
to
permit
a
timely
distribution
in
accordance
with
the
general
timing
of
distribution
provisions
in
this
Plan,
the
payment
of
any
affected
distribution(s)
shall be forfeited.
(h)
Benefits under
this Plan
will be
paid only
if the
Plan Administrator
decides in
its
discretion
that
a
Participant
or
Beneficiary
is
entitled
to
the
Benefits.
Notwithstanding
the
foregoing
or
any
provision
of
this
Plan,
a
Participant
(or
other claimant)
must exhaust
all administrative
remedies set
forth in
this
Section
7.1 or otherwise
established by the
Plan Administrator before
bringing any action
at law or
equity.
Any claim
based on a
denial of
a claim under
this Plan
must be
brought
no
later
than
the
date
which
is
two
(2)
years
after
the
date
of
the
final
denial of a
claim under this
Section 7.1.
Any claim not
brought within
such time
shall be waived and forever barred.
Exhibit 10.11.2
16
Section 8.
Rights of Employees and Participants.
Nothing
contained in
the
Plan
(or
in
any
other
documents
related
to
this
Plan
or
to
any
Benefit)
shall
confer
upon
any
Employee
or
Participant
any
right
to
continue
in
the
employ
or
other
service
of
the
Company
or
any
member
of
the
Controlled
Group
or
constitute
any
contract or
limit
in any
way
the
right
of
the
Company
or
any
member
of
the Controlled
Group to
change such
person's compensation
or other
benefits or
position
or to terminate the employment of such person with or without cause.
Section 9.
Awards in Foreign
Countries.
The
Board
or
its
delegate
shall
have
the
authority
to
adopt
such
modifications,
procedures, and
subplans as
may be
necessary or
desirable to
comply with
provisions of
the
laws
of
foreign
countries
in
which
the
Company
or
Participating
Subsidiaries
may
operate to
assure the
viability of
the Benefits
of Participants
employed in
such countries
and to meet the purpose of this Plan.
Section 10.
Amendment and Termination.
The Board
reserves the
right to
amend this
Plan from
time to
time, to
terminate the
Plan
entirely
at
any
time,
and
to
delegate
such
authority
as
the
Board
deems
necessary
or
desirable;
provided,
however,
that
no
amendment
may
affect
the
balance
in
a
Participant’s
account on
the effective
date
of
the
amendment; and,
further
provided, the
Company shall remain
liable for any
Benefits accrued under
this Plan prior
to the date
of
amendment or termination.
Section 11.
Method of Providing Payments.
(a)
Nonsegregation.
Amounts
deferred
pursuant
to
this
Plan
and
the
crediting
of
amounts to
a Participant’s
accounts shall
represent
the Company’s
unfunded and
unsecured
promise
to
pay
compensation
in
the
future.
With
respect
to
said
amounts, the relationship of
the Company and a Participant
shall be that of
debtor
Exhibit 10.11.2
17
and
general
unsecured
creditor.
While
the
Company
may
make
investments
for
the
purpose
of
measuring
and
meeting
its
obligations
under
this
Plan
such
investments shall remain the sole property of the
Company subject to claims of its
creditors generally,
and shall
not be deemed
to form or
be included in
any part of
the Participant’s accounts.
(b)
Funding.
It is
the intention
of the
Company that
this
Plan shall
be unfunded
for
federal tax
purposes and
for purposes
of Title
I of
ERISA.
All amounts
payable
under this
Plan
shall
be paid
solely
from
the
general assets
of
the
Company
and
any
rights
accruing
to
a
Participant
under
this
Plan
shall
be
those
of
a
general
creditor; provided, however,
that the Company
may establish one
or more grantor
trusts to
satisfy part
or all
of the
Company's Plan
payment obligations
so long
as
this
Plan
remains
unfunded
for
purposes
of
sections
201(2),
301(a)(3),
and
401(a)(1) of ERISA.
Section 12.
Miscellaneous Provisions.
(a)
Except
as
otherwise
provided
herein,
the
Plan
shall
be
binding
upon
the
Company,
its successors and
assigns, including but
not limited to
any corporation
which may acquire all or
substantially all of the Company's
assets and business or
with or into which the Company may be consolidated or merged.
(b)
This Plan
shall be
construed, regulated,
and administered
in accordance
with
the
laws of the State of Texas
except to the extent that said laws have been preempted
by
the
laws
of
the
United
States.
The
forum
and
venue
for
any
suit
brought
regarding any claim under this Plan shall be in Harris County, Texas.
(c)
If
any
provision
of
this
Plan
shall
be
held
illegal
or
invalid
for
any
reason,
said
illegality
or
invalidity
shall
not
affect
the
remaining
provisions
hereof;
instead,
each
provision
shall
be
fully
severable,
and
this
Plan
shall
be
construed
and
enforced as if said illegal or invalid provision had never been included herein.
(d)
For
purposes
of
this
Plan,
electronic
communications
and
signatures
shall
be
considered to be
in writing if
made in conformity
with procedures which
the Plan
Administrator may adopt from time to time.
Exhibit 10.11.2
18
(e)
The
Plan
Administrator,
in
its
sole
discretion,
may
direct
that
a
payment
to
be
made
to
an
incompetent
or
disabled
person,
whether
because
of
minority
or
mental
or
physical
disability,
instead
be
made
to
the
guardian
or
legal
representative
of
such
person
or
to
the
person
having
custody
of
such
person
(unless prior
claim therefor
shall have
been made
by a
duly qualified
guardian or
other
legal
representative),
without
further
liability
either
on
the
part
of
the
Company
or
a
Participating
Subsidiary
or
the
Plan
for
the
amount
of
such
payment
to
the
person
on
whose
benefit
such
payment
is
made.
Any
payment
made
in
accordance
with
the
provisions
of
this
provision
shall
be
a
complete
discharge
of
any
liability
of
the
Company,
its
Subsidiaries,
and
this
Plan
with
respect to the Benefits so paid.
(f)
Payment
of
Plan
Benefits
may
be
subject
to
administrative
or
other
delays
that
result
in
payment
to
the
Participant
or
his
beneficiaries
on
a
date
later
than
the
date specified
in this
Plan or
the Participant's
Election Form.
Any such
payment
delays
will
comply
with
Code
section
409A
of
the
Code,
including
without
limitation
section
1.409A-2(b)(7)
of
the
Treasury
regulations.
No
Participant
or
Beneficiary
shall
be
entitled
to
any
additional
earnings
or
interest
in
respect
of
any such payment delays, nor shall any Participant or Beneficiary be provided any
election with respect to the timing of any delayed payment.
(g)
If
all
or
any
part
of
any
Participant's
or
Beneficiary's
Benefit
hereunder
shall
become subject to any estate, inheritance, income, employment
or other tax which
the
Company
shall
be
required
to
pay
or
withhold,
the
Company
shall
have
the
full power
and authority
to withhold
and pay
such tax
out of
any monies
or other
property
held
for
the
account
of
the
Participant
or
Beneficiary
whose
interests
hereunder
are
so
affected
(including,
without
limitation,
by
reducing
and
offsetting the Participant's or
Beneficiary's account balance).
Prior to making any
payment,
the
Company
may
require
such
releases
or
other
documents
from
any
lawful taxing authority as it shall deem necessary or desirable.
(h)
No
amount
accrued
or
payable
hereunder
shall
be
deemed
to
be
a
portion
of
an
Employee's
compensation
or
earnings
for
the
purpose
of
any
other
employee
benefit
plan
adopted
or
maintained
by
the
Company,
nor
shall
this
Plan
be
deemed to amend or modify the provisions of the CPSP.
Exhibit 10.11.2
19
(i)
It is
the intention
of the
Company that,
so long
as any
of ConocoPhillips’
equity
securities
are
registered
pursuant
to
section
12(b)
or
12(g)
of
the
Securities
Exchange Act
of 1934,
this Plan
shall be
operated in
compliance with
16(b) and,
if any Plan provision or transaction is found not to comply with
section 16(b), that
provision
or
transaction,
as
the
case
may
be,
shall
be
deemed
null
and
void
ab
initio
.
Notwithstanding anything
in the
Plan to
the contrary,
the Company,
in its
absolute discretion,
may bifurcate
the Plan
so as
to restrict,
limit or
condition the
use
of
any
provision
of
the
Plan
to
Participants
who
are
officers
and
directors
subject
to
section
16(b)
without
so
restricting,
limiting
or
conditioning
the
Plan
with respect to other Participants.
(j)
This
Plan
is
intended
to
meet
the
requirements
of
Code
section
409А,
as
applicable,
in
order
to
avoid
any
adverse
tax
consequences
resulting
from
any
failure
to
comply
with
Code
section
409А
and,
as
a
result,
this
Plan
shall
be
operated
in
a
manner
consistent
with
such
compliance.
Except
to
the
extent
expressly
set
forth
in
this
Plan,
the
Participant
(and/or
the
Participant's
Beneficiary,
as applicable) shall
have no right
to dictate the
taxable year in
which
any payment hereunder that is subject to Code section 409А should be paid.
(k)
This
Ongoing
Plan
replaced
the
Frozen
Plan,
which
was
frozen
effective
as
of
December
31,
2004.
The
distribution
of
amounts
that
were
earned
and
vested
(within
the
meaning
of
Code
section
409A
and
official
guidance
issued
thereunder) under the Frozen Plan
prior to January 1,
2005 (and earnings thereon)
are
exempt
from
the
requirements
of
Code
section
409A
shall
be
made
in
accordance with the terms of the Frozen Plan.
(l)
At the Effective
Time, certain
active employees of
Phillips 66 and
members of its
controlled
group
ceased
to
participate
in
the
Plan,
and
the
liabilities,
including
liabilities related to
benefits grandfathered from Code
section 409A (
i.e.
, amounts
deferred
and
vested
prior
to
January
1,
2005),
for
these
participant's
benefits
under the Plan were transferred to the members of the Phillips 66 controlled group
and
continued
as
the
Phillips
66
Defined
Contribution
Make-Up
Plan.
ConocoPhillips
distributed its
interest
in
Phillips
66
to
its
shareholders
as
of
the
Distribution.
Notwithstanding Section
10 of
this Plan,
on and
after the
Effective
Time,
the Company,
ConocoPhillips, other
members of
the Controlled
Group (as
Exhibit 10.11.2
20
determined after
the Distribution),
the Plan,
any directors,
officers,
or employees
of
any
member
of
the
Controlled
Group
(as
determined
after
the
Distribution),
and
any
successors
thereto,
shall
have
no
further
obligation
or
liability
to,
or
on
behalf
of,
any
such
participant
with
respect
to
any
benefit,
amount,
or
right
transferred to or due under the Phillips 66 Defined Contribution Make-Up Plan.
Further, as of the
Distribution, any Phillips 66 common
stock ("Phillips 66
Stock")
held
in
the
Company
Stock
Fund
shall
be
transferred
to
a
separate
Investment
Option
under
this
Plan
that
is
accounted
for
as
if
investments
were
made
in
Phillips
66
Stock,
although
no
such
actual
investments
need
be
made,
with
accounting
entries
being
sufficient
therefor.
Investments
in
the
Phillips
66
Stock
fund
will
be
determined
as
of
the
Distribution.
On
and
after
the
Distribution, a
Participant will
be allowed
to hold
or liquidate
his or
her deemed
investment in Phillips
66 Stock.
No additional deemed investments
in Phillips 66
Stock will be allowed to be elected.
Section 13.
Effective Date of the Restated Plan.
Title II
of the Defined
Contribution Make-Up
Plan of ConocoPhillips
is hereby amended
and restated as set forth in
this 2020 Amendment and Restatement
effective as of January
1, 2020.
Executed this ____ day of December,
2019, by a duly authorized officer of the Company.
Heather G. Sirdashney
Vice President, Human Resources
DCMP Title II 2020 Restatement
12-19-2019
EX-10.19.1
Exhibit 10.19.1
1
KEY EMPLOYEE DEFERRED COMPENSATION PLAN OF
CONOCOPHILLIPS
TITLE I
(Effective for benefits earned and vested prior to
January 1, 2005)
2020 AMENDMENT AND RESTATEMENT
The Key Employee
Deferred Compensation Plan
of ConocoPhillips,
Title I
(“Title
I”), is
hereby amended
and restated
effective as
of January
1, 2020
(except where
another date
is specified herein with regard to a particular provision).
Immediately prior to
effectiveness of this
2020 Amendment and
Restatement, Title
I was
and
remains
subject
to
the
2012
Restatement
of
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips,
Title
I,
which
was
effective
as
of
the
"Effective
Time"
defined in
the Employee
Matters Agreement
by and
between ConocoPhillips
and
Phillips
66
(the
"Effective
Time")
and
conditioned
on
the
occurrence
of
the
"Distribution"
defined
in
such
Employee
Matters
Agreement
(the
"Distribution"),
together
with
the
First
Amendment
to
Title
I
of
the
Key
Employee
Deferred
Compensation Plan of ConocoPhillips (2012 Restatement), effective October 30, 2019.
Preamble
The purpose of this Plan is
to attract and retain key employees
by providing them with an
opportunity
to
defer
receipt
of
cash
amounts
which
otherwise
would
have
been
paid
to
them under various compensation programs or plans by a Participating Subsidiary.
The
Plan
is
sponsored
and
maintained
by
ConocoPhillips
Company.
The
Plan
is
the
continuation
of
the
Key
Employee
Deferred
Compensation
Plan
of
Phillips
Petroleum
Company,
of
the
Conoco
Inc.
Global
Variable
Compensation
Deferral
Program,
and
of
the portions of
the Conoco Inc.
Salary Deferral
& Savings Restoration
Plan consisting of
Salary Deferral
Obligations and
Retiree Obligations,
and all
deferrals made under
any of
Exhibit 10.19.1
2
those plans,
programs, or
arrangements shall
continue under
their terms
and the
terms of
this Plan.
Title I of the Plan is effective with regard to benefits earned and vested prior to January 1,
2005, while
Title
II of
the Plan
is effective
with regard
to benefits
earned or
vested after
December 31, 2004.
Gains, losses, earnings, or expenses shall be
allocated to the Title of
the Plan to which the underlying obligations giving
rise to them are allocated.
Other than
earnings, gains, and losses,
no further benefits
shall accrue under Title
I of this
Plan after
December 31, 2004.
This
Title
I
of
the
Plan
is
intended
(1)
to
be
a
“grandfathered”
plan
pursuant
to
Code
section 409A, as
enacted as
part of the
American Jobs
Creation Act of
2004, and
official
guidance issued thereunder,
and (2) to be “a plan
which is unfunded and is maintained
by
an
employer
primarily
for
the
purpose
of
providing
deferred
compensation
for
a
select
group of management
or highly compensated
employees” within the
meaning of sections
201(2), 301(a)(3),
and 401(a)(1)
of ERISA.
Notwithstanding any
other provision
of this
Plan,
this
Plan
shall
be
interpreted,
operated,
and
administered
in
a
manner
consistent
with these intentions.
Section 1.
Definitions.
For
purposes
of
the
Plan,
the
following
terms,
as
used
herein,
shall
have
the
meaning
specified:
(a)
“Affiliated Group”
shall mean the Company plus other subsidiaries and affiliates
in which it owns, directly or through
a subsidiary or affiliate, a 5%
or more equity
interest.
(b)
“Award”
shall
mean
the
United
States
cash
dollar
amount
(i)
allotted
to
an
Employee
under
the
terms
of
an
Incentive
Compensation
Plan
or
a
Long
Term
Incentive
Plan,
or
(ii)
required
to
be
credited
to
an
Employee’s
Deferred
Compensation
Account
pursuant
to
an
Incentive
Compensation
Plan,
the
Long
Term
Incentive
Compensation
Plan,
the
Strategic
Incentive
Plan,
a
Long
Term
Exhibit 10.19.1
3
Incentive
Plan,
or
any
similar
plans,
or
any
administrative
procedure
adopted
pursuant
thereto,
or
(iii)
credited
as
a
result
of
a
Participant’s
deferral
of
the
receipt
of
the
value
of
the
Stock
which
would
otherwise
be
delivered
to
an
Employee
in
the
event
restrictions
lapse
on
Restricted
Stock
or
Restricted
Stock
Units
or
the
settlement
of
Restricted
Stock
Units
previously
awarded
or
which
may
be
awarded
to
the
Participant
pursuant
to
an
Incentive
Compensation
Plan,
the Long Term
Incentive Compensation Plan, the Strategic Incentive Plan,
a Long
Term
Incentive
Plan,
an
Omnibus
Securities
Plan,
or
any
similar
plans,
or
any
administrative procedure
adopted pursuant
thereto, or
(iv) credited
resulting from
a
lump
sum
distribution
from
any
of
the
Company’s
non-qualified
retirement
plans
and/or
plans
which
provide
for
a
retirement
supplement,
or
(v)
resulting
from the
forfeiture of
Restricted Stock,
required by
Phillips Petroleum
Company,
of
key
employees
who
became
employees
of
GPM
Gas
Corporation,
or
(vi)
credited as a
result of an
Employee’s
deferral of the
receipt of the
lump sum cash
payment from the
Employee’s
account in
the Defined Contribution
Makeup Plan,
or
(vii)
credited
as
a
result
of
an
Employee’s
voluntary
reduction
of
Salary,
or
(viii)
credited
as
a
result
of
an
Employee’s
deferral
of
a
Performance
Based
Incentive Award,
or (ix) any
other amount determined
by the Committee
to be an
Award
under the
Plan.
Sections 2
and 3
of this
Plan shall
not apply
with respect
to Awards
included under (ii), (v),
and (ix) above and a
participant receiving such
an Award
shall be
deemed, with
respect thereto,
to have
elected a
Section 5(b)(i)
payment
option
in
10
annual
installments
commencing
about
one
year
after
retirement at age 55 or above, but subject to revision under the terms of this Plan.
(c)
“Beneficiary”
shall
mean
a
person
or
persons
or
the
trustee
of
a
trust
for
the
benefit of
a person
designated by
a Participant
to receive,
in the
event of
death,
any
unpaid
portion
of
a
Participant's
Benefits
from
this
Plan,
as
provided
in
Section 7.
(d)
“Benefit”
shall
mean
an
obligation
of
the
Company
to
pay
amounts
from
the
Plan.
(e)
“Board”
shall
mean
the
Board
of
Directors
of
the
Company,
as
it
may
be
comprised from time to time.
(f)
“Chief Executive
Officer”
or
“CEO”
shall mean
the Chief
Executive Officer
of
Exhibit 10.19.1
4
the Company.
(g)
“Committee”
shall mean the Nonqualified Plans Benefit
Committee as appointed
from
time
to
time
by
the
Board;
provided,
however,
that
until
a
successor
is
appointed by
the Board,
the individual
serving as
the Company’s
Vice
President
with
responsibility
over
human
resources
shall
be
sole
member
of
the
Committee..
(h)
“Company”
shall
mean
ConocoPhillips
Company,
a
Delaware
corporation,
or
any successor corporation.
The Company is a subsidiary of ConocoPhillips.
(i)
“Conoco
Inc.
Global
Variable
Compensation
Deferral
Program”
shall
mean
the
Conoco
Inc.
Global
Variable
Compensation
Deferral
Program,
prior
to
its
merger into this Plan on October 3, 2003.
(j)
“Conoco
Inc.
Salary
Deferral
&
Savings
Restoration
Plan”
shall
mean
the
Conoco Inc. Salary
Deferral & Savings
Restoration Plan, prior
to its
merger into
this Plan on October 3, 2003.
(k)
“ConocoPhillips”
shall
mean
ConocoPhillips,
a
Delaware
corporation,
or
any
successor
corporation.
ConocoPhillips
is
a
publicly
held
corporation
and
the
parent of the Company.
(l)
“Deferred
Compensation
Account”
shall
mean
an
account
established
and
maintained
for
each
Participant
in
which
is
recorded
the
amounts
of
Awards
deferred by a
Participant, the deemed
gains, losses, and
earnings accrued thereon,
and payments made therefrom all in accordance with the terms of the Plan.
(m)
“Defined
Contribution
Makeup
Plan”
shall
mean
the
Defined
Contribution
Makeup Plan of ConocoPhillips,
or any similar plan or successor plans.
(n)
“Disability”
shall
mean
the
inability,
in
the
opinion
of
the
Company’s
Medical
Director, of a Participant, because of an injury or sickness, to work at a reasonable
occupation
that
is
available
with
the
Company,
a
Participating
Subsidiary,
or
another subsidiary of the Company.
(o)
“Election
Form”
shall mean
a
written
form,
including
one
in
electronic
format,
provided by
the Plan
Administrator pursuant
to which
a Participant
may elect
the
time and form of payment of his or her Benefits under the Plan.
(p)
“Eligible
Employee”
shall
mean
an
Employee
who
is
eligible
to
receive
an
Award
and at the time
of the Award
is classified as a
ConocoPhillips salary grade
Exhibit 10.19.1
5
19 or above or any equivalent salary grade at a Participating Subsidiary.
(q)
“Employee”
shall
mean
any
individual
or
Rehired
Participant
who
satisfies
the
conditions
of
Section
5(j)
who
is
a
salaried
employee
of
the
Company
or
of
a
Participating
Subsidiary.
Employee
shall
also
include
Participants
who
are
employed
by
a
member
of
the
Affiliated
Group
and
former
employees
of
a
member
of
the
Affiliated
Group
who
Retire
or
are
Laid
Off
and
are
eligible
to
receive
a
lump
sum
distribution
from
non-qualified
retirement
plans.
Employee
shall
also
include
any
individual
or
Rehired
Participant
who
was
hired
as
a
salaried
employee
of
ConocoPhillips
Services
Inc.
on
or
after
January
1,
2003,
and
is
classified
as
a
ConocoPhillips
salary
grade 19
or
above or
any
equivalent
salary grade at a Participating Subsidiary.
Notwithstanding the foregoing, prior to
October
3,
2003,
Employee
shall
not
include
anyone
who
is
classified
as
a
Heritage
Conoco
Employee.
On
and
after
October
3,
2003,
Employee
shall
include anyone who is classified as a Heritage Conoco Employee.
(r)
“ERISA”
shall mean
the Employee
Retirement Income
Security Act
of 1974,
as
amended from time to time, or
any
successor statute.
(s)
“Exchange
Act”
shall
mean
the
Securities
Exchange
Act
of
1934,
as
amended
and in effect from time to time, or any successor statute.
(t)
“Heritage
Conoco
Employee”
shall
mean
an
individual
employed
by
Conoco
Inc., Conoco Pipe
Line Company,
or Louisiana Gas Systems
Inc. prior to January
1,
2003;
provided,
however,
that
an
individual
who
has
been
terminated
from
employment with
a member
of the
Affiliated Group
at any
time and
rehired by
a
member
of
the
Affiliated
Group
after January
1,
2003,
shall
not
be
considered a
Heritage Conoco Employee for purposes of this Plan.
(u)
“Incentive
Compensation
Plan”
shall
mean
the
ConocoPhillips
Variable
Cash
Incentive
Program,
the
Incentive
Compensation
Plan
of
Phillips
Petroleum
Company,
or
the
Annual
Incentive
Compensation
Plan
of
Phillips
Petroleum
Company,
the
Special
Incentive
Plan
for
Former
Tosco
Executives,
the
Conoco
Inc.
Global
Variable
Compensation
Plan,
or
a
similar
plan
of
a
Participating
Subsidiary, or any similar or successor plans, or all, as the context may require.
(v)
“Layoff”
or
“Laid Off”
shall mean
an applicable
termination of
employment by
reason
of
layoff
under
the
Phillips
Layoff
Plan
or
the
Phillips
Work
Force
Exhibit 10.19.1
6
Stabilization
Plan,
an
applicable
Qualifying
Event
(without
there
being
a
Disqualifying
Event)
under
the
Conoco
Severance
Pay
Plan,
or
layoff
or
redundancy under
any
other
layoff
or
redundancy
plan
which
the
Company,
any
Participating Subsidiary,
or any
other member
of the
Affiliated Group
may adopt
from
time
to
time.
If
all
or
any
portion
of
the
benefits
under
the
layoff
or
redundancy
plan
are
contingent
on
the
employee’s
signing
a
general
release
of
liability,
such termination shall
not be considered
as a Layoff
for purposes of
this
Plan
unless
the
employee
executes
and
does
not
revoke
a
general
release
of
liability, acceptable to the Company,
under the terms of such layoff or redundancy
plan.
(w)
“Long-Term
Incentive
Compensation
Plan”
shall
mean
the
Long-Term
Incentive
Compensation
Plan
of
Phillips
Petroleum
Company,
which
was
terminated December 31, 1985.
(x)
“Long-Term
Incentive Plan”
shall mean the
ConocoPhillips Performance
Share
Program,
the
ConocoPhillips
Restricted
Stock
Program,
the
Phillips
Petroleum
Company
Long-Term
Incentive
Plan,
or
a
similar
or
successor
plan
of
any
of
them, established under an Omnibus Securities Plan.
(y)
“Newhire Employee”
shall mean any
Employee who
is hired or
rehired during a
calendar year.
(z)
“Omnibus
Securities
Plan”
shall
mean
the
Omnibus
Securities
Plan
of
Phillips
Petroleum
Company,
the
2002
Omnibus
Securities
Plan
of
Phillips
Petroleum
Company,
the 1998 Stock
and Performance Incentive
Plan of ConocoPhillips,
the
1998 Key
Employee Stock
Plan of
ConocoPhillips, or
a similar
or successor
plan
of any of them.
(aa)
“Participant”
shall mean
a person
for whom
a Deferred
Compensation Account
is maintained.
(bb)
“Participating
Subsidiary”
shall
mean
a
subsidiary
of
the
Company,
of
which
the
Company
beneficially
owns,
directly
or
indirectly,
more
than
50%
of
the
aggregate voting
power of
all outstanding
classes and
series of
stock, where
such
subsidiary
has
adopted
one
or
more
plans
making
participants
eligible
for
participation
in
this
Plan
and
one
or
more
Employees
of
which
are
Potential
Participants.
Exhibit 10.19.1
7
(cc)
“Plan”
shall
mean
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips.
The Plan is sponsored and maintained by the Company.
(dd)
“Plan
Administrator”
shall
mean
the
Vice
President,
Human
Resources
of
the
Company, or his or her successor.
(ee)
“Plan Year
”
shall mean January 1 through December 31.
(ff)
“Potential Participant”
shall mean
a person
who has
received a
notice specified
in Section 2 or in Section 5 (h).
(gg)
“Rehired
Participant”
shall
mean
a
Participant
who,
subsequent
to
Retirement
or
Layoff,
is
rehired
by
the
Company,
or
any
subsidiary
of
the
Company,
and
whose employment status is classified as regular full-time or its equivalent.
(hh)
“Restricted Stock”
and
“Restricted Stock Units”
shall mean respectively shares
of
Stock
and
units
each
of
which
shall
represent
a
hypothetical
share
of
Stock,
which have certain restrictions attached to the ownership thereof or the delivery of
shares pursuant thereto.
(ii)
“Retiree
Obligations”
shall
mean
obligations
to
former
employees
who
have
retired on or
after the earliest
retirement date available
under the Retirement
Plan
of
Conoco
and
who
are
Participants
in
this
Plan
arising
from
deferrals
made
as
participants in
the Conoco
Inc. Salary
Deferral &
Savings Restoration
Plan prior
to its merger into this Plan.
(jj)
“Retirement”
or
“Retire”
or
“Retiring”
shall mean
termination of
employment
with the Company
or any subsidiary
of the Company
on or after
the earliest early
retirement
date
at
age
55
or
above
as
defined
in
the
ConocoPhillips
Retirement
Plan
(or,
with
respect
to
a
Heritage
Conoco
Employee,
the
Retirement
Plan
of
Conoco) or of the applicable retirement plan
of a member of the Affiliated
Group.
(kk)
“Retirement
Income
Plan”
shall mean
the ConocoPhillips
Retirement Plan
(or,
with respect to a Heritage Conoco Employee, the Retirement Plan of Conoco) or a
similar
retirement
plan
of
the
Participating
Subsidiary
pursuant
to
the
terms
of
which the Participant retires.
(ll)
“Salary
Deferral
Obligations”
shall
mean
obligations
to
Employees
who
are
Participants
in
this
Plan arising
from
salary deferrals
made
as
participants
in
the
Conoco
Inc. Salary
Deferral
&
Savings
Restoration
Plan
prior
to
its
merger
into
Exhibit 10.19.1
8
this Plan.
(mm)
“Settlement
Date”
shall
mean
the
date
on
which
all
acts
under
an
Incentive
Compensation
Plan
or
the
Long-Term
Incentive
Compensation
Plan
or
actions
directed
by
the
Committee,
as
the
case
may
be,
have
been
taken
which
are
necessary to make an Award
payable to the Participant.
(nn)
“Salary”
shall mean
the monthly
equivalent rate
of pay
for
an Employee
before
adjustments for any before-tax voluntary reductions.
(oo)
“Stock”
means shares of common stock of ConocoPhillips, par value $.01.
(pp)
“Strategic Incentive Plan”
shall mean the Strategic
Incentive Plan portion of the
1986
Stock
Plan
of
Phillips
Petroleum
Company,
of
the
1990
Stock
Plan
of
Phillips
Petroleum
Company,
of
the
Phillips
Petroleum
Company
Omnibus
Securities Plan, and of any successor plans of similar nature.
(qq)
“Subsidiary”
shall mean any corporation
or other entity that
is treated as a
single
employer
with
ConocoPhillips
under
section
414(b), (c),
or
(m)
of
the
Code.
In
applying section
1563(a)(1), (2),
and (3)
of the
Code for
purposes of
determining
a
controlled
group
of
corporations
under
section
414(b)
of
the
Code
and
for
purposes of
determining trades
or businesses
(whether or
not incorporated)
under
common
control
under
regulation
section
1.414(c)-2
for
purposes
of
section
414(c) of the Code, the language
“at least 80%” shall
be used without substitution
as allowed under regulations pursuant to section 409A of the Code.
(rr)
“Trustee”
shall mean the trustee of
the grantor trust
established for this Plan by
a
trust agreement between the Company and the trustee, or any successor trustee.
Section 2.
Notification of Potential Participants.
(a)
Incentive
Compensation
Plan.
Each
Plan
Year,
during
October,
Eligible
Employees
who
are
expected
to
be
eligible
to
receive
an
Award
in
the
immediately following
calendar year
under
an
Incentive Compensation
Plan will
be
notified
and
given
the
opportunity,
in
a
manner
prescribed
by
the
Plan
Administrator,
to
indicate
a
preference
concerning
deferral
of
all
or
part
(in
one
percent increments) of
such Award.
Exhibit 10.19.1
9
(b)
Restricted Stock and Restricted Stock Units Lapsing.
(i)
Each Plan Year
during October, Employees
who are or will
be 55 years of
age or older prior to the end
of the following calendar year will
be notified
and
given
the
opportunity,
in
a
manner
prescribed
by
the
Plan
Administrator,
to
indicate
a
preference
to
delay
the
lapsing
of
the
restrictions
on
part
(in
one
percent
increments)
or
all
of
the
shares
of
Restricted
Stock
and/or
Restricted
Stock
Units
previously
awarded
or
which may be awarded
to the Employee under
an Incentive Compensation
Plan,
the
Long
Term
Incentive
Compensation
Plan,
a
Long-Term
Incentive Plan, the Strategic Incentive Plan, or an Omnibus Securities Plan
in
the
event
the
Compensation
Committee
takes
action
in
the
following
calendar
year
to
lapse
restrictions
on
Restricted
Stock
and/or
Restricted
Stock Units and/or settle Restricted Stock Units.
(ii)
Each
Plan
Year
during
October,
Employees
who
have
been
granted
a
special
Restricted
Stock
Award
and/or
Restricted
Stock
Unit
Award
will
be notified
and given
the opportunity,
in a
manner prescribed
by the
Plan
Administrator
to
indicate
a
preference
to
delay
the
lapsing
of
the
restrictions
on
part
(in
one
percent
increments)
or
all
of
the
shares
of
Restricted Stock
and/or Restricted
Stock Units
when the
restrictions lapse
on
the
Special
Restricted
Stock
and/or
Restricted
Stock
Units
or
the
Restricted
Stock
Units
are
settled
based
on
the
terms
of
the
Special
Restricted
Stock
and/or
Restricted
Stock
Unit
Awards
in
the
following
year.
(iii)
Such indication of
preference as outlined in
(i) above may
be made within
60 days
of the
amendment of
this Plan
providing for
the notice;
provided,
however,
that
such
indication
of
preference
must
be
made
no
later
than
June
6,
2003,
for
such
Awards
that
would
otherwise
be
lapsed
or
settled
later in 2003.
(c)
Restricted Stock and Restricted Stock Unit Awards
Deferral.
(i)
Each Plan Year
during October, Employees
who are or will
be 55 years of
age or older prior to the end of the calendar
year will be notified and given
the
opportunity,
in
a
manner
prescribed
by
the
Plan
Administrator,
to
Exhibit 10.19.1
10
indicate a
preference concerning
the deferral
of the
receipt of
the value
of
all or part (in one
percent increments) of the Stock
which would otherwise
be delivered
to the
Employees in
the event,
during the
following calendar
year,
the
Compensation
Committee
takes
action
to
lapse
restrictions
on
Restricted
Stock
and/or
Restricted
Stock
Units
and/or
settle
Restricted
Stock
Units
previously
awarded
or
which
may
be
awarded
to
the
Employees
under
an
Incentive
Compensation
Plan,
the
Long
Term
Incentive
Compensation
Plan,
a
Long
Term
Incentive
Plan,
the
Strategic
Incentive Plan, or an Omnibus Securities Plan.
(ii)
Employees
who
have
been
granted
a
special
Restricted
Stock
Award
and/or Restricted
Stock
Units Award
may,
in the
year preceding
the year
in
which
the
restrictions
are
scheduled
to
lapse
or
the
Restricted
Stock
Units are to
be settled, indicate
a preference concerning
the deferral of
the
value of
all or
part
(in one
percent increments)
of
the stock
which would
otherwise
be
delivered
to
the
Employees
in
the
next
calendar
year
when
the
restrictions
lapse
on
the
special
Restricted
Stock
and
/or
Restricted
Stock Units or
the Restricted Stock Units
are settled based on
the terms of
the
special
Restricted
Stock
Awards
and/or
Restricted
Stock
Units
Awards.
(iii)
Employees who
are Laid
Off during
or after
the Plan
Year
they reach
age
50 may no
later than 30
days after being
notified of Layoff,
in the manner
prescribed by the Plan
Administrator, indicate
a preference concerning the
deferral
of
the
receipt
of
the
value
of
all
or
part
(in
one
percent
increments)
of
the
Stock
which
would
be
otherwise
be
delivered
to
the
Employees
in
the
event
Restricted
Stock
Units,
which
have
been
granted
in exchange
for Restricted
Stock pursuant
to the
Exchange offer
initiated
by the Company on December 17, 2001, are settled.
(iv)
Such indication of
preference as outlined in
(i) above may
be made within
60 days
of the
amendment of
this Plan
providing for
the notice;
provided,
however,
that
such
indication
of
preference
must
be
made
no
later
than
June
6,
2003,
for
such
Awards
that
would
otherwise
be
lapsed
or
settled
later in 2003.
Exhibit 10.19.1
11
(d)
Lump
Sum
Distribution
from
Non-Qualified
Retirement
Plans.
With
respect
to
the lump sum distribution permitted from the Company’s
non-qualified retirement
plans
and/or
plans
which
provide
for
a
retirement
supplement,
Employees
may
indicate,
in
a
manner
prescribed
by
the
Plan
Administrator,
a
preference
concerning
deferral
of
all
or
part
(in
one
percent
increments)
of
such
lump
sum
distribution.
(e)
Lump
Sum
from
Defined
Contribution
Makeup
Plan.
Employees
who
will
receive
a
lump
sum
cash
payment
from
their
account
under
the
Defined
Contribution
Makeup
Plan,
may
indicate,
in
a
manner
prescribed
by
the
Plan
Administrator,
a
preference
concerning
deferral
of
all
or
part
(in
one
percent
increments) of such payment.
(f)
Salary
Reduction.
Annually,
Employees
and
Newhire
Employees
on
the
U.S.
dollar
payroll
may
elect,
in
a
manner
prescribed
by
the
Plan
Administrator,
a
voluntary reduction
of Salary
for each
pay period
of the
following calendar
year,
or
for
Newhire
Employees
the
remainder
of
the
calendar
year
in
which
they
are
hired,
in
which
case
the
Company
will
credit
a
like
amount
as
an
Award
hereunder, provided
that the
amount of
such voluntary
reduction shall
not be
less
than 1% nor more than 50% of the Employee’s
Salary per pay period (and may be
further limited by the Plan
Administrator such that the
resulting salary that is
paid
is
sufficient
to
satisfy
all
benefit
plan
deductions,
tax
deductions,
elective
deductions, and other deductions required to be withheld by the Company).
(g)
Performance Based Incentive Award
.
Each year, during October,
Employees who
are eligible
to receive
a
Performance Based
Incentive Award
in the
immediately
following
calendar
year
will
be
notified
and
given
the
opportunity,
in
a
manner
prescribed by the
Plan Administrator,
to indicate
a preference for
the award
to be
paid as cash,
deferred to
their KEDCP account,
or issued
as Restricted Stock
or a
combination of cash, deferred compensation and Restricted Stock.
Section 3.
Indication of Preference or Election to Defer Award.
(a)
Incentive Compensation Plan.
If a Potential Participant prefers to defer under this
Plan
all
or
any
part
of
the
Award
to
which
a
notice
received
under
Section
2(a)
Exhibit 10.19.1
12
pertains,
the
Potential
Participant
must
indicate
such
preference,
in
a
manner
prescribed by
the
Plan
Administrator,
(i)
if
the
Potential
Participant
is
subject to
section
16
of
the
Exchange
Act,
to
the
Committee,
or
(ii)
if
the
Potential
Participant
is
not
subject
to
section
16
of
the
Exchange
Act,
to
the
CEO.
The
Potential Participant’s
preference must be received on
or before October 31
of the
year
in
which
said
Section
2(a)
notice
was
received.
Such
indication
must
state
the
portion
of
the
Award
the
Potential
Participant
desires
to
be
deferred.
If
an
indication is
not received by
October 31, the
Potential Participant
will be deemed
to have elected
to receive
and not to
defer any such
Incentive Compensation Plan
award.
Such
indication
of
preference,
if
accepted,
becomes
irrevocable
on
November 1
of the
year in
which the
indication is
submitted to
the Committee
or
CEO, except that, in the event of any of the following:
(i)
the
Employee
is
demoted
to
a
job
classification/grade
that
is
no
longer
eligible to receive an Award
from an Incentive Compensation Plan,
(ii)
the
Employee’s
employment
status
is
classified
to
a
status
other
than
regular full-time or its equivalent, or
(iii)
the Employee
is receiving
Unavoidable Absence
Benefits (UAB)
pay such
that
the
pay
received
is
less
than
his/her
pay
had
been
prior
to
being
on
UAB,
the
Employee
can
request,
subject
to
approval
by
the
Plan
Administrator,
that
his/her indication
of preference
to defer,
whether approved
or not,
be revoked
for
that Incentive Compensation Plan Award.
The
Committee
or
CEO,
as
applicable,
shall
consider
such
indication
of
preference as submitted
and shall decide
whether to accept
or reject the
preference
expressed.
(b)
Restricted
Stock
and
Restricted
Stock
Unit
Awards
Lapsing.
If
a
Potential
Participant
prefers
to
delay
the
lapsing
of
the
restrictions
on
part
or
all
of
the
shares
of
Restricted
Stock
and/or
Restricted
Stock
Units
to
which
a
notice
received under
Section 2(b)
pertains, the
Potential Participant
must indicate
such
preference
in
a
manner
prescribed
by
the
Plan
Administrator,
(i)
if
the
Potential
Participant is subject
to section
16 of
the Exchange
Act, to
the Committee,
or (ii)
Exhibit 10.19.1
13
if the Potential
Participant is not
subject to section
16 of the
Exchange Act, to
the
CEO.
The
Potential
Participant’s
preference
must
state
the
percentage
of
the
shares and/or
units on
which the
lapsing is
to be
delayed.
If an
indication
is not
received by
October 31,
the Potential
Participant will
be deemed
to have
elected
to
have
the
restrictions
lapsed
if
the
Compensation
Committee
takes
action
to
lapse
restrictions
or
as
specified
under
the
terms
of
the
Special
Restricted
Stock
and/or Restricted Stock
Unit Awards.
If the Potential
Participant prefers to
delay
the
lapsing
of
the
restrictions
on
part
or
all
of
the
shares
of
Restricted
Stock
or
Restricted Stock
Units awarded
under an
Incentive Compensation
Plan, the
Long
Term
Incentive
Compensation
Plan,
a
Long
Term
Incentive
Plan,
or
Strategic
Incentive
Plan,
those
shares
and/or
units
will
be
subject
to
another
indication
of
preference in
the following
year.
If the
Potential Participant
prefers to
delay the
lapsing
of
the
restrictions
on
part
or
all
of
the
shares
of
Restricted
Stock
or
Restricted Stock
Units from
Special Stock
Awards,
those shares
and/or units
will
remain restricted
and the
Employee will
receive a
notice to
indicate a
preference
for such
shares when
the Employee
is or
will be
55 years
of age
or older
prior to
the end of the calendar year as specified in Section 2(b)(i).
(c)
Restricted
Stock
or
Restricted
Stock
Unit
Deferral.
If
a
Potential
Participant
prefers to defer under
this Plan the
value of all or
any part of the
Restricted Stock
or Restricted
Stock Units
to which
a notice
received under
Section 2(c)
pertains,
the Potential Participant
must indicate such
preference, in a
manner prescribed by
the
Plan
Administrator,
(i)
if
the
Potential
Participant
is
subject
to
section
16
of
the
Exchange
Act,
to
the
Committee,
or
(ii)
if
the
Potential
Participant
is
not
subject
to
section
16
of
the
Exchange
Act,
to
the
CEO.
The
Potential
Participant’s
preference must
be received
on or
before October
31 of
the
year in
which
said
Section
2(c)
notice
was
received.
Such
indication
must
state
the
portion of the value of the Restricted Stock
or Restricted Stock Units the Potential
Participant desires
to be
deferred.
If an
indication is
not received
by October
31,
the Potential
Participant
will
be deemed
to have
elected to
receive
any
shares or
units for which the restrictions
are lapsed.
Such indication of preference becomes
irrevocable on November
1 of the
year in which
the indication is
submitted to the
Committee
or
CEO.
The
Committee
or
CEO,
as
applicable, shall
consider
such
Exhibit 10.19.1
14
indication of
preference as
submitted and
shall decide
whether to
accept or
reject
the
preference
expressed.
A
deferral
of
the
value
of
the
Restricted
Stock
or
Restricted Stock Units will
be paid under the terms
of Section 5(b)(i) hereof in
10
annual
installments
commencing
about
one
year
after
Retirement
at
age
55
or
above,
but
subject
to
revision
under
the
terms
of
this
Plan.
Such
approved
indication of
preference shall
also apply
to any
Restricted Stock
Units granted
in
exchange
for
shares
of
Restricted
Stock
pursuant
to
the
Exchange
offer
initiated
by the Company on December 17, 2001.
(d)
Lump
Sum
Distribution
from
Non-Qualified
Retirement
Plans.
If
a
Potential
Participant prefers to defer under
this Plan all or
part of the lump
sum distribution
to
which
Section
2(d)
pertains,
the
Potential
Participant
must
indicate
such
preference, in
a manner
prescribed by
the
Plan Administrator,
(i) if
the Potential
Participant is subject to section 16 of the Exchange Act, to the Committee or (ii) if
the
Potential
Participant
is
not
subject
to
section
16
of
the
Exchange
Act,
to
the
CEO.
The
Potential
Participant’s
preference
must
be
received
in
the
period
beginning
90
days
prior
to
and
ending
no
less
than
30
days
prior
to
the
date
of
commencement
of
retirement
benefits
under
such
plans.
Such
indication
must
state the
portion
of the
lump
sum distribution
the Potential
Participant desires
to
be deferred.
The Committee or CEO, as applicable, shall consider such indication
of
preference
as
submitted
and
shall
decide
whether
to
accept
or
reject
the
preference
expressed
as
soon
as
practicable.
Such
indication
of
preference,
if
accepted, becomes irrevocable on the date of such acceptance.
(e)
Lump
Sum
from
Defined
Contribution
Makeup
Plan.
If
a
Potential
Participant
prefers to defer under this
Plan all or part of
the lump sum cash payment
to which
Section 2(e) pertains,
the Potential
Participant must
indicate such preference,
in a
manner
prescribed
by
the
Plan
Administrator,
(i)
if
the
Potential
Participant
is
subject to section 16 of
the Exchange Act, to the Committee
or (ii) if the Potential
Participant
is
not
subject
to
section
16
of
the
Exchange
Act,
to
the
CEO.
The
Potential
Participant’s
preference
must
be
received
in
the
period
beginning
365
days prior to
and ending
no less than
90 days
prior to
the Participant’s
retirement
date at
age 55
or above
except that
if
a Potential
Participant is
notified of
layoff
during
or
after
the
year
in
which
the
Potential
Participant
reaches
age
50,
the
Exhibit 10.19.1
15
Potential
Participant’s
preference
must
be
received
no
later
than
30
days
after
being notified
of layoff.
Such indication
must state
the portion
of the
lump
sum
payment the Potential Participant
desires to be deferred.
The Committee or CEO,
as applicable,
shall consider
such indication
of preference
as submitted
and shall
decide whether to accept or
reject the preference expressed as
soon as practicable.
Such
indication
of
preference,
if
accepted,
becomes
irrevocable
on
the
date
of
such
acceptance.
A
deferral
of
the
lump
sum
from
the
Defined
Contribution
Makeup Plan
will
be paid
under the
terms of
Section 5(b)(i)
hereof in
10 annual
installments commencing about
one year after
Retirement at
age 55 or
above, but
subject to revision under the terms of the Plan.
(f)
Salary
Reduction.
If
a
Potential
Participant
elects
to
voluntarily
reduce
Salary
and
receive
an
Award
hereunder
in
lieu
thereof,
the
Potential
Participant
must
make an election, in the manner prescribed by the Plan Administrator,
which must
be received on or
before October 31 prior
to the beginning of
the calendar year of
the elected deferral
or for Newhire
Employees as
soon as practicable
within a 30-
day
period
after
their
first
day
of
employment
or
reemployment.
Such
election
must be
in writing
signed by
the Potential
Participant, and
must state
the amount
of
the
salary
reduction
the
Potential
Participant
elects.
Such
election
becomes
irrevocable
on
October
31
prior
to
the
beginning
of
the
calendar
year
or
for
Newhire Employees after
the 30-day period
after their first
day of employment
or
reemployment, except that in the event of any of the following:
(i)
the Employee is demoted to a job classification/grade that is no longer
eligible to receive an Award
from an Incentive Compensation Plan,
(ii)
the Employee’s employment status is classified to a status other than
regular full-time or its equivalent, or
(iii)
the Employee is receiving Unavoidable Absence Benefits (UAB) pay such
that the pay received is less than his/her pay had been prior to being on
UAB,
the Employee can request, subject to approval by
the Plan Benefits Administrator,
that
his/her
election
to
voluntarily
reduce
his/her
salary
be
revoked
for
the
remainder of the calendar year.
Exhibit 10.19.1
16
An
Award
in
lieu
of
voluntarily
reduced
salary
will
be
paid
under
the
terms of
Section
5(b)(i)
hereof in
10
annual installments
commencing about
one
year after Retirement at age 55 or above, but subject to revision under the terms of
the Plan.
(g)
Performance Based Incentive
Award.
The Potential Participant
who is eligible
to
receive
a
Performance
Based
Incentive
Award
in
the
immediately
following
calendar
year,
must
indicate
a
preference,
in
a
manner
prescribed
by
the
Plan
Administrator,
(i)
if
the
Potential
Participant
is
subject
to
section
16
of
the
Exchange Act,
to the
Committee, or
(ii) if
the Potential
Participant is
not subject
to
section
16
of
the
Exchange
Act,
to
the
CEO.
The
Potential
Participant’s
preference
must
be
received
on
or
before
October
31
of
the
year
in
which
said
Section
2(g)
notice
was
received.
Such
indication
must
state
the
portion
of
the
award the Potential Participant desires to be in cash, the portion to be deferred and
the portion
to be
in Restricted
Stock.
If an
indication is
not received
by October
31 the Potential Participant will be deemed to have elected to
receive the award as
cash.
Such
indication
of
preference
becomes
irrevocable
on
November
1
of
the
year
in
which
the
indication
is
submitted
to
the
Committee
or
CEO.
The
Committee or
CEO, as
applicable, shall
consider such
indication of
preference as
submitted and shall decide whether to accept or reject the preference expressed.
Section 4.
Deferred Compensation Accounts.
(a)
Credit
for
Deferral.
Amounts
deferred
pursuant
to
Section
3(a)
and
Section
5(h)(1)
will
be
credited
to
the
Participant’s
Deferred
Compensation
Account
as
soon
as
practicable,
but
not
less
than
30
days
after
the
Settlement
Date
of
the
Incentive
Compensation
Plan.
Amounts
deferred
pursuant
to
Section
3(c)
and
Section 5(h)(2) will be credited,
as applicable, as soon as
practicable, but not later
than 30 days after the date as of
which the restrictions lapse at the market value
of
the underlying
Restricted Stock
or the
shares represented
by the
Restricted Stock
Units
awarded under
an
Incentive
Compensation
Plan,
the
Long
Term
Incentive
Compensation
Plan,
a
Long
Term
Incentive
Plan
or
a
Strategic
Incentive
Plan
Performance Period
which began
prior to
January 1,
2003.
For this
purpose, the
Exhibit 10.19.1
17
market value
of the
underlying
Restricted Stock
or the
shares represented
by the
Restricted
Stock
Units,
as
applicable,
shall
be
based
on
the
higher
of
(i)
the
average of the high
and low selling
prices of the Stock
on the date the
restrictions
lapse or the last trading day before
the day the restrictions lapse if
such date is not
a trading
day or
(ii) the
average of
the high
three monthly
Fair Market
Values
of
the
Stock
during
the
twelve
calendar
months
preceding
the
month
in
which
the
restrictions lapse.
The monthly
Fair Market
Value
of the
Stock is
the average
of
the daily Fair Market Value
of the Stock for each trading day of the month.
The
market
value
of
the
underlying
Restricted
Stock
or
the
shares
represented by
the Restricted
Stock Units
awarded under
a Long
Term
Incentive
Plan,
under
an
Incentive
Compensation
Plan
that
began
on
or
after
January
1,
2003, under
an Omnibus
Securities Plan
(with regard
to awards
made on
or after
January 1,
2003), and
for the
Special Stock
Awards
issued on
October 22,
2002,
shall be
the monthly
average Fair
Market Value
of the
Stock during
the calendar
month
preceding
the
month
in
which
the
restrictions
lapse
or
shares
are
to
be
delivered as
applicable.
The monthly
average Fair
Market Value
of the
Stock is
the average of the daily Fair Market Value
of the Stock for each trading day of the
month.
The
daily
Fair
Market
Value
of
the
Stock
shall
be
deemed
equal
to
the
average
of
the
high
and
low
selling
prices
of
the
Stock
on
the
New
York
Stock
Exchange.
Amounts
deferred
pursuant
to
Section
3(e)
and
3(f)
and
Section
5(h)(3)
will
be
credited
to
the
Participant’s
Deferred
Compensation
Account
as
soon
as
practicable,
but
not
later
than
30
days
after
the
cash
payment
would
have
been
made had it
not been
deferred.
Amounts deferred
pursuant to other
provisions of
this
Plan
shall be
credited
as
soon
as
practicable
but
not
later
than
30
days
after
the date the Award would
otherwise be payable.
(b)
Designation
of
Investments.
The
amount
in
each
Participant’s
Deferred
Compensation
Account
shall
be
deemed
to
have
been
invested
and
reinvested
from time
to time,
in such
“eligible securities”
as the
Participant shall
designate.
Prior
to
or
in
the
absence
of
a
Participant’s
designation,
the
Company
shall
designate an “eligible security” in
which the Participant’s
Deferred Compensation
Exhibit 10.19.1
18
Account shall
be deemed
to have
been invested
until designation
instructions are
received from the Participant. Eligible securities are those securities designated by
the
Chief
Financial
Officer
of
the
Company,
or
his
successor.
The
Chief
Financial Officer
of the
Company may
include as
eligible securities,
stocks listed
on
a
national
securities
exchange,
and
bonds,
notes,
debentures,
corporate
or
governmental,
either
listed
on
a
national
securities
exchange
or
for
which
price
quotations
are
published
in
The
Wall
Street
Journal
and
shares
issued
by
investment
companies
commonly
known
as
“mutual
funds”.
The
Participant’s
Deferred
Compensation
Account
will
be
adjusted
to
reflect
the
deemed
gains,
losses,
and
earnings
as
though
the
amount
deferred
was
actually
invested
and
reinvested
in
the
eligible
securities
for
the
Participant’s
Deferred
Compensation
Account.
Notwithstanding
anything
to
the
contrary
in
this
Section
4(b),
in
the
event the
Company
(or
any
trust maintained
for this
purpose) actually
purchases
or sells such
securities in the
quantities and at
the times the
securities are deemed
to
be
purchased
or
sold
for
a
Participant’s
Deferred
Compensation
Account,
the
Account shall be adjusted accordingly to reflect the price actually paid or received
by
the
Company
for
such
securities
after
adjustment
for
all
transaction
expenses
incurred (including without limitation brokerage fees and stock transfer taxes).
In
the
case
of
any
deemed
purchase
not
actually
made
by
the
Company,
the
Deferred
Compensation
Account
shall
be
charged
with
a
dollar
amount
equal
to
the
quantity
and
kind
of
securities
deemed
to
have
been
purchased
multiplied
by
the
fair
market
value
of
such
security
on
the
date
of
reference and shall
be credited with
the quantity and
kind of securities
so deemed
to have been
purchased.
In the case
of any deemed
sale not actually
made by the
Company,
the
account
shall
be
charged
with
the
quantity
and
kind
of
securities
deemed to have
been sold, and
shall be credited
with a dollar
amount equal to
the
quantity
and
kind
of
securities
deemed
to
have
been
sold
multiplied
by
the
fair
market value of
such security
on the date
of reference.
As used in
this paragraph
“fair market
value” means
in the
case of
a listed
security the
closing price
on the
date of reference,
or if there
were no sales
on such
date, then the
closing price on
the
nearest
preceding
day
on
which
there
were
such
sales,
and
in
the
case
of
an
Exhibit 10.19.1
19
unlisted
security
the
mean
between
the
bid
and
asked
prices
on
the
date
of
reference, or
if no
such prices
are available
for such
date, then
the mean
between
the
bid
and
asked
prices
to
the
nearest
preceding
day
for
which
such
prices
are
available.
The
Chief
Financial
Officer
of
the
Company
may
also
designate
a
third
party
to
provide
services
that
may
include
record
keeping,
Participant
accounting,
Participant
communication,
payment
of
installments
to
the
Participant,
tax
reporting,
and
any
other
services
specified
by
the
Company
in
agreement with such third party.
(c)
Payments.
A Participant’s
Deferred Compensation Account
shall be debited
with
respect
to
payments
made
from
the
account
pursuant
to
this
Plan
as
of
the
date
such payments are made from the account.
The payment shall be made as soon as
practicable, but no later than 30 days, after the installment payment date.
If
any
person
to
whom
a
payment
is
due
hereunder
is
under
legal
disability as
determined in
the sole
discretion of
the Plan
Administrator,
the Plan
Administrator
shall
have
the
power
to
cause
the
payment
due
such
person
to
be
made
to
such
person’s
guardian
or
other
legal
representative
for
the
person’s
benefit,
and
such
payment
shall
constitute
a
full
release
and
discharge
of
the
Company, the Plan Administrator,
and any fiduciary of the Plan.
(d)
Statements.
At
least
one
time
per
year
the
Plan
Administrator
(or
a
third
party
acting for the Plan Administrator) will furnish each Participant a written statement
setting
forth
the
current
balance
in
the
Participant’s
Deferred
Compensation
Account, the amounts
credited or
debited to
such account
since the
last statement
and
the
payment
schedule
of
deferred
Awards,
and
deemed
gains,
losses,
and
earnings accrued
thereon as
provided by
the deferred
payment option
selected by
the Participant.
This provision shall be deemed satisfied if
the Plan Administrator
(or
a
third
party
acting
for
the
Plan
Administrator)
makes
such
information
available
through
electronic
means,
such
as
a
web
site,
and
informs
affected
Participants of the availability of the information and the manner of accessing it.
Exhibit 10.19.1
20
Section 5.
Payments from Deferred Compensation Accounts.
(a)
Election
of
Method
of
Payment for
an
Incentive Compensation
Plan
Award.
At
the time
a Potential
Participant submits
an indication
of preference
to defer
all or
any
part
of
an
Award
under
an
Incentive
Compensation
Plan
as
provided
in
Section
3(a)
above,
the
Potential
Participant
shall
also
elect
in
a
manner
prescribed by the
Plan Administrator,
which of the
payment options, provided
for
in Paragraph (b)
of this Section,
shall apply to
the deferred portion
of said Award
adjusted
for
any
deemed
gains,
losses,
and
earnings
accrued
thereon
credited
to
the
Participant’s
Deferred
Compensation
Account
under
this
Plan.
Subject
to
Paragraphs
(e),
(g),
and
(h)
of
this
Section,
if
the
Committee
or
CEO,
as
appropriate,
accepts
the
Potential
Participant’s
indication
of
preference,
the
election
of
the
method
of
payment
of
the
amount
deferred
shall
become
irrevocable.
(b)
Payment Options.
A Potential Participant may elect, using an Election
Form or in
such
other
manner
prescribed
by
the
Plan
Administrator,
to
have
the
deferred
portion of an Incentive Compensation
Plan Award
adjusted for any deemed gains,
losses, and earnings accrued thereon paid:
(i)
(Post-Retirement)
in
1
to
15
annual
installments,
in
2
to
30
semi-annual
installments,
or in
4 to
60
quarterly installments,
the payment
of
the
first
of
any
of
such
installments
to
commence
on
the
first
day
of
the
first
calendar
quarter
which
is
on
or
after
the
first
anniversary
of
(x)
the
Potential Participant’s
first day of Retirement at
age 55 or above (or at
age
50
or
above
for
a
Heritage
Conoco
Employee
who
was
employed
by
Conoco Inc.
or its
affiliates
on August
30, 2002
if such
Heritage Conoco
Employee
is
eligible
for
early
retirement
under
the
Retirement
Plan
of
Conoco) or
(y) the
Potential
Participant’s
first day
of Layoff
at age
50 or
above, or
(ii)
(Date
Certain)
with
regard
only
to
the
deferred
portion
of
an
Incentive
Compensation
Award,
in
1
to
15
annual
installments,
in
2
to
30
semi-
annual
installments,
or
in
4
to
60
quarterly
installments,
the
payment
of
the
first
of
any
of
such
installments
to
commence
on
the
first
day
of
Exhibit 10.19.1
21
calendar quarter which is designated
by the Participant, is at
least one year
after the
date on
which the
election is
made, and
is not
later than
the 65
th
birthday
of
the
Participant;
provided,
however,
that
in
the
event
of
termination
of
employment
from
the
Affiliated
Group
by
a
Heritage
Conoco
Employee
who
had
made
deferral
of
amounts
from
the
Conoco
Inc.
Global
Variable
Compensation
Plan,
the
balance
of
such
deferred
amounts (adjusted
for earnings,
gains, and
losses) shall
be paid
in a
lump
sum
as
soon
as
practicable
after
termination,
notwithstanding
an
installment election made pursuant to this Paragraph, or
(iii)
(Pre-
Retirement
)
otherwise,
in
a
lump
sum
paid
as
soon
as
practicable
following
the
Participant’s
termination
from
employment
with
the
Affiliated Group.
(iv)
In the event that no election is properly and timely made with regard to the
time and method of payment under Section 5(b)(i) or (ii), payment shall be
made
in
10
annual
installments,
the
payment
of
the
first
of
any
of
such
installments
to
commence
on
the
first
day
of
the
first
calendar
quarter
which is
on or
after the
first anniversary
of (x)
the Potential
Participant’s
first
day
of
Retirement
at
age
55
or
above
(or
at
age
50
or
above
for
a
Heritage
Conoco
Employee
who
was
employed
by
Conoco
Inc.
or
its
affiliates
on
August
30,
2002
if
such
Heritage
Conoco
Employee
is
eligible
for
early
retirement
under the
Retirement
Plan
of
Conoco)
or
(y)
the Potential Participant’s first day of Layoff at age 50 or above.
(c)
Election
of
Method
of
Payment
of
the
Value
of
Restricted
Stock
and
Restricted
Stock Units.
As provided
in Section
3(c) above,
a deferral
of the
value of
all or
part of the
Restricted Stock or
Restricted Stock Units
will be considered
payment
option (b)(i) of this Section subject to Paragraphs (e) and (g) of this Section.
(d)
Election of
Method of
Payment of
a Lump
Sum Distribution
from Non-Qualified
Retirement
Plans.
At
the
time
a
Potential
Participant
submits
an
indication
of
preference to defer
all or
part of the
lump sum distribution
as provided in
Section
3(d) above, the Potential
Participant shall also
elect in a manner
prescribed by the
Plan
Administrator
which
payment
option
shall
apply
to
the
deferred
lump
sum
adjusted for
any gains,
losses, and
earnings to
be accrued
thereon credited
to the
Exhibit 10.19.1
22
Participant’s
Deferred
Compensation
Account
under
this
Plan.
The
payment
options
are annual
installments
of not
less than
1 nor
more than
15, semi-annual
installments
of not
less than
2 nor
more than
30, or
quarterly installments
of not
less
than
4
nor
more
than
60.
The
first
installment
shall
commence
as
soon
as
practicable
after
any
date
specified
by
the
Potential
Participant,
so
long
as
such
date is the first day
of a calendar quarter
and is at least one
year and not later than
five years
from the
date the
payout option
was elected.
Subject to
Paragraph (g)
of
this
Section,
if
the
Committee
or
CEO,
as
appropriate,
accepts
the
Potential
Participant’s
indication
of
preference,
the
election
of
the
method
of
payment
of
the amount deferred shall become irrevocable.
(e)
Payment
Option
Revisions.
If
a
Section
5(b)(i)
payment
option
applies
to
any
part
of
the
balance
of
a
Participant’s
Deferred
Compensation
Account,
the
Participant may revise such payment option as follows:
(i)
Prior to Retirement.
The Participant at any time during a period beginning
365
days
prior
to
and
ending
90
days
prior
to
the
date
the
Participant
Retires
at
age
55
or
above
may,
with
respect
to
the
total
of
all
amounts
subject to
such payment
option at
the time
of the
Participant’s
Retirement
at
age
55
or
above,
in
the
manner
prescribed
by
the
Plan
Administrator,
revise such payment option and
elect one of the payment
options specified
in
(e)(iv)
of
this
Section
to
apply
to
such
total
amount
in
place
of
such
payment option.
(ii)
Upon Layoff.
If a Participant
who is eligible
to Retire or
who is Laid
Off
during or
after the
year in
which the
Participant reaches
age 50
is notified
of Layoff, the Participant may,
no later than 30 days after being notified of
Layoff,
in
the
manner
prescribed
by
the
Plan
Administrator,
revise
such
payment option and elect one of the payment options specified in (e)(iv) of
this Section to apply to such total amount in place of such payment option.
(iii)
If Disabled.
The Participant may at any time during a period from the date
of
the
beginning
of
the
qualifying
period
for
the
Company’s
Long
Term
Disability Plan
or similar
plan to
no later
than 90
days prior
to the
end of
such period, or within 30 days of the amendment of this Plan providing for
such election,
in the
manner
prescribed
by the
Plan
Administrator,
revise
Exhibit 10.19.1
23
such
payment
option
and
elect
one
of
the
payment
options
specified
in
(e)(iv) of
this
Section
to
apply
to
the
total
of
all amounts
subject
to
such
payment
option;
provided,
however,
that
after
the
payments
have
begun,
such payments
may be
made in
a different
manner if,
the
Participant due
to
an
unanticipated
emergency
caused
by
an
event
beyond
the
control
of
the
Participant
results
in
financial
hardship
to
the
Participant,
so
request
and the CEO gives written consent to the method of payment requested.
(iv)
Payment Options
After Revision.
If a Participant
revises a Section
5(b)(i)
payment option
as specified
in (e)(i),
(e)(ii), or
(e)(iii) of
this Section,
the
Participant
may
select
payments
in
annual
installments
of
not
less
than
1
nor more
than 15,
in semi-annual
installments of
not less
than 2
nor more
than
30,
or
in
quarterly
installments
of
not
less
than
4
nor
more
than
60,
with
the
first
installment
to
commence
as
soon
as
practicable
following
any date specified by the Participant so
long as such date is the
first day of
a calendar quarter, is on
or after the Participant’s
first day of Retirement at
age 55
or above
or the
first day
the Participant
is no
longer an
Employee
following Layoff, is at least
one year and no more than
five years from the
date the payment option was revised.
(f)
Installment
Amount.
The
amount
of
each
installment
shall
be
determined
by
dividing
the
balance
in
the
Participant’s
Deferred
Compensation
Account
as
of
the date
the installment
is to
be paid,
by the
number of
installments remaining
to
be paid (inclusive of the current installment).
(g)
Death
of
Participant.
Upon
the
death
of
a
Participant,
the
Participant’s
Beneficiary
or
Beneficiaries
designated
in
accordance
with
Section
7,
shall
receive
payments
in
accordance
with
the
payment
option
selected
by
the
Participant,
if
death
occurred
after
such
payments
had
commenced;
or
if
death
occurred before payments have commenced,
the Beneficiary may select
payments
in
annual
installments
of
not
less
than
1
nor
more
than
15,
in
semi-annual
installments of not less than 2 nor more than 30, or in quarterly installments of not
less
than
4
nor
more
than
60
with
the
first
installment
to
commence
as
soon
as
practicable following any
date specified by the
beneficiary so long
as such date
is
the first
day of
a calendar
quarter and
is at
least
one year
and no
more
than
five
Exhibit 10.19.1
24
years
from
the
date
the
payment
option
is
selected
and
is
not
later
than
the
date
the
deceased
Participant
would
have
been
age
65;
provided,
however,
such
payments
may
be
made
in
a
different
manner
if
the
Beneficiary
or
Beneficiaries
entitled to receive or receiving
such payments, due to an unanticipated
emergency
caused
by
an
event
beyond
the
control
of
the
beneficiary
or
beneficiaries
that
results
in
financial
hardship
to
the
Beneficiary
or
Beneficiaries,
so
requests
and
the CEO gives written consent to the method of payment requested.
(h)
Disability
of
Participant.
In
the
event
a
Participant
or
Employee
becomes
disabled, the
individual
may,
in the
period
from
the date
of the
beginning
of the
qualifying
period
for
the
Company’s
Long
Term
Disability
Plan
to no
later than
90
days
prior
to
the
end
of
such
period,
or
within
30
days
of
the
amendment
of
this Plan providing for such election, indicate a preference, in a manner prescribed
by the Plan Administrator, for any of the following:
(1)
To
defer
part
or
all
of
any
Incentive
Compensation
Plan
Award
the
Employee
is
eligible
to
receive
in
the
immediately
following
calendar
year,
(2)
To
defer
part
or
all
of
the
value
of
the
Stock
which
would
otherwise
be
delivered
to
the
Employee
when
the
restrictions
lapse
on
any
Restricted
Stock or Restricted Stock Units or Restricted Stock Units are settled, or
(3)
To
defer
part
or
all
of
the
value
from
their
account
under
the
Defined
Contribution Makeup
Plan which
would otherwise
be paid
as a
lump sum
to the Participant.
Such
indications
of
preference
shall
be
subject
to
approval
by
the
Committee
if
the
Potential
Participant
is
subject
to
section
16
of
the
Exchange
Act
or
by
the
CEO if
the Potential
Participant is
not subject
to section
16 of
the Exchange
Act.
The
Committee
or
CEO,
as
applicable,
shall
consider
such
indication
or
preference as submitted and shall decide whether to accept or reject the preference
expressed.
Such
indications
of
preference,
if
accepted,
become
irrevocable
on
the
date of such acceptance.
A deferral of any amount will be paid under
the terms of
Section
5(b)(i)
hereof
in
ten
(10)
annual
installments,
but
subject
to
revision
as
specified under the terms of this Plan.
Exhibit 10.19.1
25
(i)
Termination
of
Employment.
In
the
event
a
Participant’s
employment
with
the
Company,
any
Participating
Subsidiary,
or
any
other
subsidiary
of
the
Company
terminates
for
any
reason
other
than
death,
Retirement
at
age
55
or
above,
Disability,
or Layoff
during or
after the
year in
which the
Participant reaches
age
50,
the
entire
balance
of
the
Participant’s
Deferred
Compensation
Account
shall
be paid to the Participant in one lump
sum as soon as practicable after the date
the
Participant
terminates
employment,
except
that
a
Participant
who
becomes
employed
by
a
member
of
the
Affiliated
Group
immediately
after
terminating
employment with
the Company
or Participating
Subsidiary shall
not receive
their
benefit
under
the
Plan
until
the
Participant
terminates
employment
from
the
Affiliated
Group;
provided,
however,
the
Committee,
in
its
sole
discretion,
may
elect
to
make
such
payments
in
the
amounts
and
on
such
schedule
as
it
may
determine.
(j)
Rehire
of
Participant.
In
the
event
a
Participant
is
a
Rehired
Participant,
he/she
will
be
eligible
to
receive
notifications
as
specified
in
Section
2
and
will
be
eligible to
submit an
Indication of
Preference or
Election to
Defer as
specified in
Section
3,
if
the
Participant
agrees
to
the
suspension
of
payments
from
his/her
Deferred
Compensation
Account
during
the
period
of
reemployment
by
the
Company.
Upon
termination
of
reemployment,
such
payments
shall
resume
on
the same schedule as was in effect at the time the Participant previously Retired or
was Laid Off.
Section 6.
Special Provisions for Former ARCO Alaska Employees.
Notwithstanding any
provisions to
the contrary,
in order
to comply
with the
terms of
the
Master
Purchase
and
Sale
Agreement
(“Sale
Agreement”)
by
which
the
Company
acquired certain
Alaskan assets
of Atlantic
Richfield Company
(“ARCO”), a
Participant
who was eligible to participate in
the ARCO employee benefit plans immediately
prior to
becoming
an
Employee
and
who
was
not
employed
by
ARCO
Marine,
Inc.
(a
“former
ARCO
Alaska
employee”)
may,
in
a
manner
prescribed
by
the
Plan
Administrator,
indicate a preference or make an election:
(a)
To
reduce voluntarily salary and
receive an Award
in the amount
of the reduction
Exhibit 10.19.1
26
credited to, at the Employee’s
election, (i) an account under
this Plan or (ii) for
so
long
as
the
ARCO
Executive
Deferral
Plan
will
accept
such
deferrals
of
salary,
but
not
beyond
December
31,
2001,
an
account
under
the
ARCO
Executive
Deferral Plan; or
(b)
To
defer
any
Award
payable
to
a
former
ARCO
employee
who
is
involuntarily
terminated
prior
to
April
18,
2002,
in
lieu
of
a
target
ARCO
Annual
Incentive
Plan
(AIP)
award,
and
at
the
Employee’s
election
credit
the
Award
to
(i)
an
account under this Plan or (ii) to the ARCO Executive Deferral Plan; or
(c)
To
defer
the
Final
ARCO
Supplemental
Executive
Retirement
Plan
(SERP)
benefit that
will
be
calculated as
of
the
earlier
of
April 17,
2002, or
the
date
the
former ARCO employee voluntarily or involuntarily
terminates employment from
the
Company
or
any
Participating
Subsidiary
to
the
ARCO
Executive
Deferral
Plan; or
(d)
To
defer the
value of
the restricted
stock granted
on July
31, 2000,
to an
account
under
this
Plan
when
the
restrictions
lapse
on
July
31,
2001,
July
31,
2002,
and
July 31,
2003; provided
that such
indications of
preference shall
be made
in July
of
the
year
preceding
the
calendar
year
when
the
restrictions
are
scheduled
to
lapse
or
as
soon
as
practicable
after
July
31,
2000,
for
the
restrictions
on
the
shares that are to be lapsed on July 31, 2001; or
(e)
For a former
ARCO Alaska
employee who was
classified as a
grade 7 or
8 under
ARCO’s
job
classification
system
and
was
eligible
under
ARCO’s
Executive
Deferral Plan
to
voluntarily
reduce salary
and
defer
the
amount
of
the
voluntary
salary reduction and
who was classified
as a grade
31 or below
at that time
under
Phillips
Petroleum
Company’s
job
classification
system,
to
make
an
annual
election to
voluntarily reduce
salary and
defer the
amount of
the voluntary
salary
reduction for salary received from July 31, 2000, through December 31, 2000, and
for
the
five
years
from
2001
through
2005
and
receive
a
salary
deferral
credit
under this Plan.
All indications
of preference
in Sections
6(a), (b),
and (c)
are subject
to approval
by the
Compensation Committee
if the
Employee
is subject
to
section
16 of
the
Exchange Act
and by the CEO if the Employee is not subject to section 16 of the Exchange Act.
Exhibit 10.19.1
27
Section 7.
Designation of Beneficiary.
A Participant
may
designate
a
Beneficiary
or
Beneficiaries
to receive
the
entire
balance
of
the
Participant’s
Deferred
Compensation
Account
by
giving
signed
written
notice
of
such designation
to the
Plan Administrator
upon forms
supplied by
and delivered
to the
Plan
Administrator
and
may
revoke
such
designations
in
writing;
provided,
that
writing
and
signing
may
be
done
by
any
electronic
means
approved
by
the
Plan
Administrator.
The
Participant
may
from
time
to
time
change
or
cancel
any
previous
beneficiary
designation
in
the
same
manner.
The
last
beneficiary
designation
received
by
the
Plan
Administrator shall
be controlling
over any
prior
designation and
over any
testamentary
or
other
disposition.
After
acceptance
by
the
Plan
Administrator
of
such
written
designation, it
shall take
effect as
of the
date on
which it
was signed
by the
Participant,
whether the
Participant is
living at
the time
of such
receipt, but
without prejudice
to the
Company or
the CEO
on account of
any payment
made under
this Plan
before receipt of
such
designation.
If
no
designation
of
a
Beneficiary
is
on
file
with
the
Plan
Administrator
at
the
time
of
the
death
of
the
Participant
or
such
designation
is
not
effective
for
any
reason
as
determined
by
the
Plan
Administrator,
then,
for
purposes
of
this
Plan,
“Beneficiary”
shall
mean,
and
such
Benefits
shall
be
paid
to,
(i)
the
Participant's
surviving
spouse
as
of
the
Participant's
date
of
death,
or
(ii)
if
there
is
no
surviving spouse as of the Participant's date of death, the Participant’s estate.
Section 8.
Nonassignability.
The
interest
of
a
Participant
or
his
Beneficiary
or
Beneficiaries
hereunder
may
not
be
sold,
transferred,
assigned,
or
encumbered
in
any
manner,
either
voluntarily
or
involuntarily,
and
any
attempt
so
to
anticipate,
alienate,
sell,
transfer,
assign,
pledge,
encumber, or
charge the
same shall be null
and void; neither
shall the Benefits
hereunder
be
liable
for
or
subject
to
the
debts,
contracts,
liabilities,
engagements,
or
torts
of
any
person
to
whom
such
Benefits
or
funds
are
payable,
nor
shall
they
be
an
asset
in
bankruptcy or subject to garnishment, attachment, or other legal or equitable proceedings.
Exhibit 10.19.1
28
Section 9.
Administration.
(a)
The
Plan
shall
be
administered
by
the
Plan
Administrator.
The
Plan
Administrator may
delegate to
employees of
the Company
or any
member of
the
Controlled
Group
the
authority
to
execute
and
deliver
such
instruments
and
documents,
to
do
all
such
acts
and
things,
and
to
take
such
other
steps
deemed
necessary,
advisable, or
convenient for
the effective
administration of
the Plan
in
accordance
with
its
terms
and
purpose,
except
that
the
Plan
Administrator
may
not
delegate
any
discretionary
authority
with
respect
to
substantive
decisions
or
functions regarding
the Plan
or Benefits
under the
Plan.
The Plan
Administrator
may designate
a third
party to
provide services
that may
include record
keeping,
Participant accounting, Participant communication, payment of installments
to the
Participant,
tax
reporting,
and
any
other
services
specified
in
an
agreement
with
such third
party.
The Plan
Administrator may
adopt such
rules, regulations,
and
forms
as
deemed
desirable
for
administration
of
the
Plan
and
shall
have
the
discretionary
authority
to
allocate
responsibilities
under
the
Plan
to
such
other
persons
as
may
be
designated.
The
Plan
Administrator
shall
have
absolute
discretion
in
carrying
out
its
responsibilities,
and
all
interpretations,
findings
of
fact
and
resolutions
described
herein
which
are
made
by
the
Plan
Administrator
shall be binding, final and conclusive on all parties.
The Plan
Administrator
and his
or her
delegates shall
serve without
bond
and without
compensation for
services under
this Plan.
All expenses
of the
Plan
Administrator and his or her delegates for services under this Plan shall be paid by
the
Company.
None
of
the
Plan
Administrator
or
his
or
her
delegates
shall
be
liable
for
any
act
or
omission
on
his
or
her
own
part
excepting
his
or
her
own
willful
misconduct.
Without
limiting
the
generality
of
the
foregoing,
any
such
decision
or
action
taken
by
the
Plan
Administrator
or
his
or
her
delegates
in
reliance
upon
any
information
supplied
by
an
officer
of
the
Company,
the
Company's
legal
counsel,
or
the
Company's
independent
accountants
in
connection
with
the
administration
of
this
Plan
shall
be
deemed
to
have
been
taken in good faith.
Exhibit 10.19.1
29
(b)
Any
claim
for
benefits
hereunder
shall
be
presented
in
writing
to
the
Plan
Administrator
for
consideration,
grant
or
denial.
In
the
event
that
a
claim
is
denied in
whole or
in part
by the
Plan Administrator,
the claimant,
within ninety
days
of
receipt
of
said
claim
by
the
Plan
Administrator,
shall
receive
written
notice of denial.
Such notice shall contain:
(1)
a statement of the specific reason or reasons for the denial;
(2)
specific references to the pertinent provisions hereunder on which such
denial is based;
(3)
a description of any additional material or information necessary to perfect
the claim and an explanation of why such material or information is
necessary; and
(4)
an explanation of the following claims review procedure set forth in
paragraph (c) below.
(c)
Any
claimant
who
feels
that
a
claim
has
been
improperly
denied
in
whole
or
in
part
by
the
Plan
Administrator
may
request
a
review
of
the
denial
by
making
written application to
the Trustee.
The claimant shall
have the right
to review
all
pertinent documents
relating to
said claim
and to
submit issues
and comments
in
writing
to
the
Trustee.
Any
person
filing
an
appeal
from
the
denial
of
a
claim
must
do
so
in
writing
within
sixty
days
after
receipt
of
written
notice
of
denial.
The
Trustee
shall
render
a
decision
regarding
the
claim
within
sixty
days
after
receipt of
a request
for review,
unless special
circumstances require
an extension
of
time
for
processing,
in
which
case
a
decision
shall
be
rendered
within
a
reasonable time, but not later than 120
days after receipt of the request for
review.
The decision
of the
Trustee
shall be
in writing
and, in
the case
of the
denial of
a
claim in whole
or in part,
shall set forth
the same
information as is
required in an
initial notice of denial by the Plan
Administrator, other than an
explanation of this
claims
review procedure.
The
Trustee
shall
have absolute
discretion
in
carrying
out its responsibilities to make
its decision of an appeal,
including the authority to
interpret and construe the terms hereunder, and all interpretations, findings of fact,
and the decision
of the Trustee
regarding the appeal
shall be final,
conclusive and
binding on all parties.
Exhibit 10.19.1
30
(d)
Compliance
with
the
procedures
described
in
paragraphs
(b)
and
(c)
shall
be
a
condition precedent to the filing of any
action to obtain any benefit or
enforce any
right which any individual may claim hereunder.
Notwithstanding anything to the
contrary
in
the
Plan,
these
paragraphs
(b),
(c),
and
(d)
may
not
be
amended
without
the
written
consent
of
a
seventy-five
percent
(75%)
majority
of
Participants
and
Beneficiaries
and
such
paragraphs
shall
survive
the
termination
of this Plan until all benefits accrued hereunder have been paid.
(e)
Any payment to a Participant or Beneficiary,
all in accordance with the provisions
of
this
Plan,
shall
to
the
extent
thereof
be
in
full
satisfaction
of
all
claims
hereunder
against
the
Plan
Administrator,
the
Company
and
all
Participating
Subsidiaries,
any
of
which
may
require
such
Participant
or
Beneficiary
as
a
condition to
such payment
to execute
a receipt
and
release therefor
in such
form
as shall be
determined by the
Plan Administrator,
the Company or
a Participating
Subsidiary.
If a
receipt and
release is
required and
the Participant
or Beneficiary
(as
applicable)
does
not
provide
such
receipt
and
release
in
a
timely
enough
manner
to
permit
a
timely
distribution
in
accordance
with
the
general
timing
of
distribution
provisions
in
this
Plan,
the
payment
of
any
affected
distribution(s)
shall be forfeited.
(f)
Benefits under
this Plan
will be
paid only
if the
Plan Administrator
decides in
its
discretion
that
a
Participant
or
Beneficiary
is
entitled
to
the
Benefits.
Notwithstanding
the
foregoing
or
any
provision
of
this
Plan,
a
Participant
(or
other claimant) must exhaust all administrative remedies set forth in this Section 9
or otherwise
established
by the
Plan Administrator
before
bringing any
action
at
law
or
equity.
Any
claim
based
on
a
denial
of
a
claim
under
this
Plan
must
be
brought
no
later
than
the
date
which
is
two
(2)
years
after
the
date
of
the
final
denial
of
a
claim
under
this
Section
9.
Any
claim
not
brought
within
such time
shall be waived and forever barred.
Section 10.
Rights of Employees and Participants.
Nothing
contained in
the
Plan
(or
in
any
other
documents
related
to
this
Plan
or
to
any
Benefit
under
the
Plan)
shall
confer
upon
any
Employee
or
Participant
any
right
to
Exhibit 10.19.1
31
continue in the employ or
other service of the Company
or any member of the
Controlled
Group
or
constitute
any
contract
or
limit
in
any
way
the
right
of
the
Company
or
any
member of
the Controlled
Group to
change such
person's compensation
or other
benefits
or position or to terminate the employment of such person with or without cause.
Section 11.
Determination of Recipients of Awards.
The
determination
of
those
persons
who
are
entitled
to
Awards
under
an
Incentive
Compensation
Plan
and any
other
such
plans
shall
be
governed solely
by
the
terms
and
provisions
of
the
applicable
plan,
and
the
selection
of
an
Employee
as
a
Potential
Participant or
the acceptance
of an
indication of
preference to
defer an
Award
hereunder
shall not in any way entitle such Potential Participant to an Award.
Section 12.
Amendment and Termination.
Subject
to
Paragraph 9(d),
the
Board
reserves the
right
to amend
this
Plan from
time
to
time,
to
terminate
this
Plan
entirely
at
any
time,
and
to
delegated
such
authority
as
the
Board
deems
necessary
or
desirable;
provided,
however,
that
no
amendment
may
affect
the balance in a Participant’s account on the effective
date of the amendment; and, further
provided, the Company
shall remain liable
for any Benefits
accrued under this
Plan prior
to
the
date
of
amendment
or
termination.
In
the
event
of
termination
of
the
Plan,
the
Chief Executive Officer,
in his sole discretion, may
elect to have the Company
pay to the
Participant
in
one
lump
sum
as
soon
as
practicable
after
termination
of
the
Plan,
the
balance then in the Participant’s account.
Section 13.
Method of Providing Payments.
(a)
Nonsegregation.
Amounts
deferred
pursuant
to
this
Plan
and
the
crediting
of
amounts
to
a
Participant’s
Deferred
Compensation
Account
shall
represent
the
Company’s
unfunded
and
unsecured
promise
to
pay
compensation
in
the
future.
With
respect to
said
amounts,
the
relationship
of the
Company
and
a
Participant
shall be
that of
debtor and
general unsecured
creditor.
While the
Company may
Exhibit 10.19.1
32
make investments for
the purpose of
measuring and meeting
its obligations under
this Plan
such investments shall
remain the sole
property of
the Company
subject
to claims of its creditors generally, and shall not be deemed to form or be included
in any part of the Deferred Compensation Account.
(b)
Funding.
It is
the intention
of the
Company that
this
Plan shall
be unfunded
for
federal tax
purposes and
for purposes
of Title
I of
ERISA.
All amounts
payable
under this
Plan
shall
be paid
solely
from
the
general assets
of
the
Company
and
any
rights
accruing
to
a
Participant
under
this
Plan
shall
be
those
of
a
general
creditor; provided, however,
that the Company
may establish one
or more grantor
trusts to
satisfy part
or all
of the
Company's Plan
payment obligations
so long
as
this
Plan
remains
unfunded
for
purposes
of
sections
201(2),
301(a)(3),
and
401(a)(1) of ERISA.
Section 14.
Miscellaneous Provisions.
(a)
Except
as
otherwise
provided
herein,
the
Plan
shall
be
binding
upon
the
Company,
its successors and
assigns, including but
not limited to
any corporation
which may acquire all or substantially all of the Company’s
assets and business or
with or into which the Company may be consolidated or merged.
(b)
This Plan
shall be
construed, regulated,
and administered
in accordance
with
the
laws of the State of Texas
except to the extent that said laws have been preempted
by
the
laws
of
the
United
States.
The
forum
and
venue
for
any
suit
brought
regarding any claim under this Plan shall be in Harris County, Texas.
(c)
If
any
provision
of
this
Plan
shall
be
held
illegal
or
invalid
for
any
reason,
said
illegality
or
invalidity
shall
not
affect
the
remaining
provisions
hereof;
instead,
each
provision
shall
be
fully
severable,
and
this
Plan
shall
be
construed
and
enforced as if said illegal or invalid provision had never been included herein.
(d)
For
purposes
of
this
Plan,
electronic
communications
and
signatures
shall
be
considered to be
in writing if
made in conformity
with procedures which
the Plan
Administrator may adopt from time to time.
(e)
The
Plan
Administrator,
in
its
sole
discretion,
may
direct
that
a
payment
to
be
made
to
an
incompetent
or
disabled
person,
whether
because
of
minority
or
Exhibit 10.19.1
33
mental
or
physical
disability,
instead
be
made
to
the
guardian
or
legal
representative
of
such
person
or
to
the
person
having
custody
of
such
person
(unless prior
claim therefor
shall have
been made
by a
duly qualified
guardian or
other
legal
representative),
without
further
liability
either
on
the
part
of
the
Company
or
a
Participating
Subsidiary
or
the
Plan
for
the
amount
of
such
payment
to
the
person
on
whose
benefit
such
payment
is
made.
Any
payment
made
in
accordance
with
the
provisions
of
this
provision
shall
be
a
complete
discharge
of
any
liability
of
the
Company,
its
Subsidiaries,
and
this
Plan
with
respect to the Benefits so paid.
(f)
Payment
of
Plan
Benefits
may
be
subject
to
administrative
or
other
delays
that
result
in
payment
to
the
Participant
or
his
beneficiaries
on
a
date
later
than
the
date
specified
in
this
Plan
or
the
Participant's
Election
Form.
No
Participant
or
Beneficiary
shall
be
entitled
to
any
additional
earnings
or
interest
in
respect
of
any such payment delays, nor shall any Participant or Beneficiary be provided any
election with respect to the timing of any delayed payment.
(g)
If
all
or
any
part
of
any
Participant's
or
Beneficiary's
Benefits
hereunder
shall
become subject to any estate, inheritance, income, employment
or other tax which
the
Company
shall
be
required
to
pay
or
withhold,
the
Company
shall
have
the
full power
and authority
to withhold
and pay
such tax
out of
any monies
or other
property
held
for
the
account
of
the
Participant
or
Beneficiary
whose
interests
hereunder
are
so
affected
(including,
without
limitation,
by
reducing
and
offsetting the Participant's or
Beneficiary's account balance).
Prior to making any
payment,
the
Company
may
require
such
releases
or
other
documents
from
any
lawful taxing authority as it shall deem necessary or desirable.
(h)
No
amount
accrued
or
payable
hereunder
shall
be
deemed
to
be
a
portion
of
an
Employee's
compensation
or
earnings
for
the
purpose
of
any
other
employee
benefit
plan
adopted
or
maintained
by
the
Company,
nor
shall
this
Plan
be
deemed to amend or modify the provisions of the CPSP.
(i)
It is
the intention
of the
Company that,
so long
as any
of ConocoPhillips
’
equity
securities
are
registered
pursuant
to
section
12(b)
or
12(g)
of
the
Exchange
Act,
this Plan
shall be
operated in
compliance with
16(b) of
the Exchange
Act and,
if
any Plan provision
or transaction is found
not to comply
with section 16(b)
of the
Exhibit 10.19.1
34
Exchange Act,
that provision
or transaction,
as the
case may
be, shall
be deemed
null and void
ab initio
.
Notwithstanding anything
in the Plan
to the
contrary,
the
Company,
in its
absolute discretion,
may bifurcate
the Plan
so as
to restrict,
limit
or condition
the use
of any
provision of
the Plan
to Participants
who are
officers
and directors
subject to
section 16(b)
of the
Exchange Act
without so
restricting,
limiting, or conditioning the Plan with respect to other Participants.
(j)
This
Title
I was
frozen
effective
as
of
December
31,
2004,
and
was
replaced
by
Title
II
of
the
Plan.
The
distribution
of
amounts
that
were
earned
and
vested
(within
the
meaning
of
Code
section
409A
and
official
guidance
issued
thereunder)
under
Title
I
of
the
Plan
prior
to
January
1,
2005
(and
earnings
thereon) are exempt from the requirements of Code section 409A shall be
made in
accordance with the terms of the Title I of the Plan.
(k)
At the Effective
Time, certain
active employees of
Phillips 66 and
members of its
controlled
group
ceased
to
participate
in
the
Plan,
and
the
liabilities,
including
liabilities related to
benefits grandfathered from Code
section 409A (
i.e.
, amounts
deferred
and
vested
prior
to
January
1,
2005),
for
these
participant's
benefits
under the Plan were transferred to the members of the Phillips 66 controlled group
and
continued
as
the
Phillips
66
Key
Employee
Deferred
Compensation
Plan.
ConocoPhillips
distributed its
interest
in
Phillips
66
to
its
shareholders
as
of
the
Distribution.
On
and
after
the
Effective
Time,
the
Company,
other
members
of
the Affiliated Group (as determined after the Distribution), the Plan, any directors,
officers, or employees of any member of the Affiliated Group (as determined after
the
Distribution),
and
any
successors
thereto,
shall
have
no
further
obligation
or
liability
to,
or
on
behalf
of,
any
such
participant
with
respect
to
any
benefit,
amount,
or
right
transferred
to
or
due
under
the
Phillips
66
Key
Employee
Deferred Compensation Plan.
Further,
as
of
the
Distribution,
the
Restricted
Stock
and
Restricted
Stock
Units
of
ConocoPhillips
shall
be
converted
into
Restricted
Stock
and
Restricted
Stock
Units
of
ConocoPhillips
and
restricted
stock
and
restricted
stock
units
of
Phillips
66
as
provided
in
the
Agreement.
The
amounts
to
be
credited
to
a
Participant's Deferred Compensation Account under
Section 4(a) will be
based on
such Restricted Stock and
Restricted Stock Units of
ConocoPhillips and restricted
Exhibit 10.19.1
35
stock and restricted stock units of Phillips 66 after the Distribution.
Furthermore,
with
regard
to
any
valuation
that
occurs
after
the
Distribution
and
which
requires
valuation
of
Stock
or
the
common
stock
of
Phillips
66
("Phillips
66
Common
Stock"),
or
of
both,
from
a
time
on
or
before
the
Distribution
and
from
a
time
after
the
Distribution,
then
the
following
shall
apply, in
order to allow the valuation to take into
account the distribution by stock
dividend of one
share of
Phillips 66
Common Stock for
each two
shares of
Stock
held at the Distribution:
(1)
The value
of Stock
or of
Phillips 66
Common Stock determined
as of
any
date
after
the
Distribution
shall
be
determined
using
market
information
related to each;
(2)
The value of Stock determined as
of any date on or before
the Distribution
that
does
not
also
require
a
valuation
of
Stock
as
of
any
date
after
the
Distribution shall be determined using
market information related to Stock
as it traded on or before the Distribution;
(3)
The value of Stock determined
as of any date on or
before the Distribution
that also
requires a
valuation of
Stock or
of Phillips
66 Common
Stock as
of any
date
after the
Distribution
shall be
deemed
to be
two-thirds
of
the
value of
Stock determined
using market
information related
to Stock
as it
traded on or before the Distribution; and
(4)
The value
of Phillips
66 Common
Stock determined
as of
any date
on or
before the Distribution that also requires a valuation of Stock or of Phillips
66 Common Stock
as of any date
after the Distribution
shall be deemed to
be
one-third
of
the
value
of
Stock
determined
using
market
information
related to Stock as it traded on or before the Distribution.
Section 15.
Effective Date of Restated Plan.
Title
I
of
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips
is
hereby
amended and restated effective as of January 1, 2020.
Exhibit 10.19.1
36
Executed this ____ day of December 2019, by a duly authorized officer of the Company.
______________________________
Heather G. Sirdashney
Vice President, Human Resources
KEDCP Title I 2020 Restatement
12-19-2019
EX-10.19.2
Exhibit 10.19.2
1
KEY EMPLOYEE DEFERRED COMPENSATION PLAN
OF
CONOCOPHILLIPS
TITLE II
(Effective for benefits earned or vested after
December 31, 2004)
2020 AMENDMENT AND RESTATEMENT
The Key
Employee Deferred
Compensation Plan
of ConocoPhillips,
Title
II (“Title
II”),
is
hereby
amended
and
restated
effective
as
of
January
1,
2020
(except
where
another
date is specified herein with regard to a particular provision).
Immediately prior to effectiveness of this 2020 Amendment and Restatement, Title
II was
and
remains
subject
to
the
2013
Restatement
of
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips,
Title
II,
which
was
effective
as
of
January
1,
2013,
together
with
the
First
Amendment
to
Title
II
of
the
Key
Employee
Deferred
Compensation Plan of ConocoPhillips (2013 Restatement), effective October 30, 2019.
Preamble
The purpose of this Plan is
to attract and retain key employees
by providing them with an
opportunity
to
defer
receipt
of
cash
amounts
which
otherwise
would
be
paid
to
them
under various compensation programs or plans by a Participating Subsidiary.
Title I of the Plan is effective with regard to benefits earned and vested prior to January 1,
2005, while
Title
II of
the Plan
is effective
with regard
to benefits
earned or
vested after
December 31, 2004.
Gains, losses, earnings, or expenses shall be
allocated to the Title of
the Plan
to which
the underlying
obligations giving
rise to
them are
allocated.
The Plan
is sponsored and maintained by ConocoPhillips Company.
This Title
II of the
Plan is intended
(1) to comply
with Code section
409A, as enacted
as
part of the
American Jobs Creation
Act of 2004,
and official
guidance issued thereunder,
Exhibit 10.19.2
2
and (2)
to be
“a plan
which is
unfunded and
is maintained
by an
employer primarily
for
the
purpose
of
providing
deferred
compensation
for
a
select
group
of
management
or
highly
compensated
employees”
within
the
meaning
of
sections
201(2),
301(a)(3),
and
401(a)(1) of ERISA.
Notwithstanding any other
provision of this
Plan, this Plan
shall be
interpreted, operated, and administered in a manner consistent with these intentions.
Section 1.
Definitions.
For
purposes
of
the
Plan,
the
following
terms,
as
used
herein,
shall
have
the
meaning
specified:
(a)
“Award”
shall
mean
the
United
States
cash
dollar
amount
(i)
allotted
to
an
Employee
under
the
terms
of
an
Incentive
Compensation
Plan
or
a
Long
Term
Incentive
Plan,
or
(ii)
required
to
be
credited
to
an
Employee’s
Deferred
Compensation
Account
pursuant
to
the
terms
of
an
Award
or
of
an
Incentive
Compensation
Plan,
the
Long
Term
Incentive
Compensation
Plan,
the
Strategic
Incentive
Plan,
a
Long
Term
Incentive
Plan,
or
any
similar
plans,
or
any
administrative
procedure
adopted
pursuant
thereto,
or
(iii)
credited
as
a
result
of
an Employee’s voluntary reduction of Salary,
or (iv) any other amount determined
by the Committee to be an Award under the Plan.
(b)
“Beneficiary”
shall
mean
a
person
or
persons
or
the
trustee
of
a
trust
for
the
benefit
of
a
person
designated
by
a
Participant
to
receive,
in
the
event
of
death,
any
unpaid
portion
of
a
Participant's
Benefits
from
this
Plan,
as
provided
in
Section 8.
(c)
“Benefit”
shall
mean
an
obligation
of
the
Company
to
pay
amounts
from
the
Plan.
(d)
“Board”
shall
mean
the
Board
of
Directors
of
the
Company,
as
it
may
be
comprised from time to time.
(e)
“Code”
shall mean the
Internal Revenue Code
of 1986,
as amended from
time to
time, or any successor statute.
(f)
“Committee”
shall mean the Nonqualified Plans Benefit
Committee as appointed
from
time
to
time
by
the
Board;
provided,
however,
that
until
a
successor
is
Exhibit 10.19.2
3
appointed by
the Board,
the individual
serving as
the Company’s
Vice
President
with responsibility over human resources shall be sole member of the Committee.
(g)
“Company”
shall
mean
ConocoPhillips
Company,
a
Delaware
corporation,
or
any successor corporation.
The Company is a subsidiary of ConocoPhillips.
(h)
“ConocoPhillips”
shall
mean
ConocoPhillips,
a
Delaware
corporation,
or
any
successor
corporation.
ConocoPhillips
is
a
publicly
held
corporation
and
the
parent of the Company.
(i)
“Controlled Group”
shall mean ConocoPhillips and its Subsidiaries.
(j)
“Deferred
Compensation
Account”
shall
mean
an
account
established
and
maintained
for
each
Participant
in
which
is
recorded
the
amounts
of
Awards
deferred by a
Participant, the deemed
gains, losses,
earnings, or expenses
accrued
thereon,
and
payments
made
therefrom
all
in
accordance
with
the
terms
of
the
Plan.
(k)
“Distribution”
shall
have
the
same
meaning
as
that
set
forth
in
the
Employee
Matters
Agreement
by
and
between
ConocoPhillips
and
Phillips
66
dated
as
of
April 26, 2012.
(l)
“Effective Time”
shall have
the same
meaning as
that set
forth in
the Employee
Matters
Agreement
by
and
between
ConocoPhillips
and
Phillips
66
dated
as
of
April 26, 2012.
(m)
“Election
Form”
shall mean
a
written
form,
including
one
in
electronic
format,
provided by
the Plan
Administrator pursuant
to which
a Participant
may elect
the
time and form of payment of his or her Benefits under the Plan.
(n)
“Eligible
Employee”
shall
mean
an
Employee
who
is
eligible
to
receive
an
Award
and at the time
of the Award
is classified as a
ConocoPhillips salary grade
19 or above or any equivalent salary grade at a Participating Subsidiary.
(o)
“Employee”
shall
mean
any
individual
who
is
a
salaried
employee
of
the
Company or any Participating Subsidiary.
(p)
“ERISA”
shall mean
the Employee
Retirement Income
Security Act
of 1974,
as
amended from time to time, or any successor statute.
(q)
“Exchange
Act”
shall
mean
the
Securities
Exchange
Act
of
1934,
as
amended
and in effect from time to time, or any successor statute.
(r)
“Fair Market Value”
shall mean the
value described in the
applicable provision
Exhibit 10.19.2
4
of Section 4(a).
(s)
“Heritage
Conoco
Employee”
shall
mean
an
individual
employed
by
Conoco
Inc., Conoco Pipe
Line Company,
or Louisiana Gas Systems
Inc. prior to January
1,
2003;
provided,
however,
that
an
individual
who
has
been
terminated
from
employment with a
member of the
Controlled Group at
any time and
rehired by a
member of
the Controlled
Group after
January 1,
2003, shall
not be
considered a
Heritage Conoco Employee for purposes of this Plan.
(t)
“Incentive
Compensation
Plan”
shall
mean
the
ConocoPhillips
Variable
Cash
Incentive
Program,
the
Incentive
Compensation
Plan
of
Phillips
Petroleum
Company,
the
Annual
Incentive
Compensation
Plan
of
Phillips
Petroleum
Company,
the
Special
Incentive
Plan
for
Former
Tosco
Executives,
the
Conoco
Inc.
Global
Variable
Compensation
Plan,
or
a
similar
plan
of
a
Participating
Subsidiary, or any similar or successor plans, or all, as the context may require.
(u)
“Long-Term
Incentive
Compensation
Plan”
shall
mean
the
Long-Term
Incentive
Compensation
Plan
of
Phillips
Petroleum
Company,
which
was
terminated December 31, 1985.
(v)
“Long-Term
Incentive Plan”
shall mean the
ConocoPhillips Performance
Share
Program,
the
ConocoPhillips
Executive
Restricted
Stock
Unit
Program,
the
ConocoPhillips
Restricted
Stock
Unit
Program,
the
Phillips
Petroleum
Company
Long-Term
Incentive
Plan,
or
a
similar
or
successor
plan
of
any
of
them,
established under an Omnibus Securities Plan.
(w)
“Omnibus
Securities
Plan”
shall
mean
the
2014
Omnibus
Stock
and
Performance
Incentive
Plan
of
ConocoPhillips,
the
2011
Omnibus
Stock
and
Performance
Incentive
Plan
of
ConocoPhillips,
the
2009
Omnibus
Stock
and
Performance
Incentive
Plan
of
ConocoPhillips,
the
2004
Omnibus
Stock
and
Performance Incentive Plan
of ConocoPhillips, the
2002 Omnibus Securities
Plan
of
Phillips
Petroleum
Company,
the
Omnibus
Securities
Plan
of
Phillips
Petroleum
Company,
the
1998
Stock
and
Performance
Incentive
Plan
of
ConocoPhillips,
the
1998
Key
Employee
Stock
Plan
of
ConocoPhillips,
or
a
similar or successor plan of any of them.
(x)
“Participant”
shall mean
a person
for whom
a Deferred
Compensation Account
is maintained.
Exhibit 10.19.2
5
(y)
“Participating
Subsidiary”
shall
mean
a
Subsidiary
that
has
adopted
one
or
more
plans
making
participants
eligible
for
participation
in
this
Plan
and
one
or
more Employees of which are Potential Participants.
(z)
“Plan”
shall
mean
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips.
The Plan is sponsored and maintained by the Company.
(aa)
“Plan Administrator”
shall mean the Committee.
(bb)
“Plan Year
”
shall mean January 1 through December 31.
(cc)
“Potential Participant”
shall mean
a person
who has
received a
notice specified
in Section 2.
(dd)
“Restricted Stock”
and
“Restricted Stock Units”
shall mean respectively shares
of
Stock
and
units
each
of
which
shall
represent
a
hypothetical
share
of
Stock,
which have certain restrictions attached to the ownership thereof or the delivery of
shares pursuant thereto.
(ee)
“Retirement”
or
“Retire”
or
“Retiring”
shall
mean
Separation
from
Service
from the Controlled
Group on or
after age 55
or above and
on or after
the earliest
early
retirement
date
as
defined
in
applicable
title
of
the
ConocoPhillips
Retirement Plan or of the applicable retirement plan of a Participating Company.
(ff)
“Schedule
A
Employee”
shall
mean
an
Employee
whose
name
appears
in
Schedule A attached to and made a part of this Plan.
(gg)
“Separation
from
Service”
shall
mean
the
date
on
which
the
Participant
separates
from
service
with
the
Controlled
Group
within
the
meaning
of
Code
section 409A, whether
by reason of
death, disability,
retirement, or otherwise.
In
determining Separation
from Service,
with regard
to a
bona fide leave
of absence
that is
due to
any medically
determinable physical
or mental
impairment that
can
be expected to result in
death or can be expected
to last for a continuous
period of
not
less
than
six
months,
where
such
impairment
causes
the
Employee
to
be
unable
to
perform
the
duties
of
his
or
her
position
of
employment
or
any
substantially similar
position of
employment, a
29-month period
of absence
shall
be
substituted
for
the
six-month
period
set
forth
in
section
1.409A-1(h)(1)(i)
of
the regulations issued under section 409A of the Code, as allowed thereunder.
(hh)
“Settlement
Date”
shall
mean
the
date
on
which
all
acts
under
an
Incentive
Compensation
Plan,
a
Long-Term
Incentive
Plan,
or
the
Long-Term
Incentive
Exhibit 10.19.2
6
Compensation
Plan
or
actions
directed
by
the
Committee,
as
the
case
may
be,
have
been
taken
which
are
necessary
to
make
an
Award
payable
to
the
Participant.
(ii)
“Salary”
shall mean
the monthly
equivalent rate
of pay
for
an Employee
before
adjustments for any before-tax voluntary reductions.
(jj)
“Stock”
means shares of common stock of ConocoPhillips, par value $.01.
(kk)
“Strategic Incentive Plan”
shall mean the Strategic
Incentive Plan portion of the
1986
Stock
Plan
of
Phillips
Petroleum
Company,
of
the
1990
Stock
Plan
of
Phillips
Petroleum
Company,
of
the
Phillips
Petroleum
Company
Omnibus
Securities Plan, and of any successor plans of similar nature.
(ll)
“Subsidiary”
shall mean any corporation
or other entity that
is treated as a
single
employer
with
ConocoPhillips
under section
414(b),
(c),
or
(m)
of
the
Code.
In
applying section
1563(a)(1), (2),
and (3)
of the
Code for
purposes of
determining
a
controlled
group
of
corporations
under
section
414(b)
of
the
Code
and
for
purposes of
determining trades
or businesses
(whether or
not incorporated)
under
common
control
under
regulation
section
1.414(c)-2
for
purposes
of
section
414(c) of the Code, the language
“at least 80%” shall
be used without substitution
as allowed under regulations pursuant to section 409A of the Code.
(mm)
“Trustee”
shall mean the trustee of
the grantor trust established
for this Plan by a
trust agreement between the Company and the trustee, or any successor trustee.
Section 2.
Notification of Potential Participants.
(a)
Incentive
Compensation
Plan.
Each
Plan
Year
after
2008,
at
such
times
as
the
Plan
Administrator
may
determine,
Eligible
Employees
who
are
expected
to
be
eligible to receive an Award
for the immediately following calendar year under an
Incentive Compensation
Plan will
be notified
and given
the opportunity
to make
an
election,
using
the
Election
Form
or
in
such
other
manner
prescribed
by
the
Plan
Administrator,
to
defer
all
or
part
of
such
Award
(although
with
regard
to
deferral
of
an
Award
from
the
Performance
Share
Program
for
Performance
Period XI [2013 -2015], an election may defer either none or all of
the Award,
not
a part less than all thereof); provided, however, that
in the case of an Award
under
Exhibit 10.19.2
7
an
Incentive
Compensation
Plan
determined
by
the
Plan
Administrator
to
be
"performance-based
compensation"
under
Code
section
409A,
the
Plan
Administrator
may
delay
the
notification
and
opportunity
to
make
an
election
until no later than June 30 of the year for which the Award
is to be made.
(b)
Salary
Reduction.
With
regard
to
each
Plan
Year,
at
such
times
as
the
Plan
Administrator may
determine, Eligible
Employees on
the U.S.
dollar payroll
will
be
notified
and
given
the
opportunity
to
make
an
election,
using
the
Election
Form
or
in
such
other
manner
prescribed
by
the
Plan
Administrator,
to
make
a
voluntary reduction
of Salary
for each
pay period
of the
following calendar
year,
in
which
case
the
Company
will
credit
a
like
amount
as
an
Award
hereunder,
provided
that
the
amount
of
such
voluntary
reduction
shall
not
be
less
than
1%
nor more than 50% of the Eligible Employee’s Salary per pay period.
(c)
Long-Term
Incentive Plan.
With
regard to
each
Plan
Year,
at
such
times
as
the
Plan Administrator may
determine, Employees who
are expected to
be eligible
to
receive an Award
for services rendered
during a performance
period beginning in
the
immediately
following
calendar
year
under
a
Long-Term
Incentive Plan
will
be
notified
and
given
the
opportunity
to
make
an
election,
using
the
Election
Form or in such other manner prescribed by the
Plan Administrator, to defer
all or
part of such Award
;
provided, that this
paragraph shall not apply
to Awards
made
under the
Restricted
Stock Unit
Program or
its
predecessor,
the Restricted
Stock
Program;
and
provided,
further,
that
this
paragraph
shall
be
effective
only
with
regard
to
Awards
made
pursuant
to
the
Performance
Share
Program
for
performance
periods
beginning
in
2013
or
thereafter;
and
provided,
further,
that
this
paragraph
shall
be
effective
with
regard
to
Awards
made
pursuant
to
the
Executive Restricted Stock
Unit Program in
2018 and
2019 but
shall not
apply to
Awards
made
pursuant
to
the
Executive
Restricted
Stock
Unit
Program
for
Awards made
after December 31, 2019
Section 3.
Election to Defer Award or Reduce Salary.
(a)
Incentive Compensation
Plan.
If a
Potential Participant
elects to
defer under
this
Plan
all
or
any
part
of
the
Award
to
which
a
notice
received
under
Section
2(a)
Exhibit 10.19.2
8
pertains,
the
Potential
Participant
must
make
such
election,
using
the
Election
Form or
in such
other manner
prescribed by
the
Plan Administrator,
which must
be
received
on
or
before
December
31
of
the
year
in
which
said
Section
2(a)
notice
was
received
(or
at
such
earlier
time
as
may
be
prescribed
by
the
Plan
Administrator).
The
Potential
Participant's
election
shall
become
irrevocable
on
December 31 of the year in which said Section 2(a) notice was received (except in
the
case
of
an
election
for
an
Award
under
an
Incentive
Compensation
Plan
determined
by
the
Plan
Administrator
to
be
"performance-based
compensation"
under Code section 409A,
the election shall become
irrevocable on June 30
of the
year
for
which
the
Award
is
to
be
made,
if
so
designated
by
the
Plan
Administrator),
subject
to
the
provisions
Section
5(d).
If
an
election
is
not
properly
made
and
timely
received,
the
Potential
Participant
will
be
deemed
to
have
elected
to
receive
and
not
to
defer
any
such
Incentive
Compensation
Plan
Award.
(b)
Salary Reduction.
If a
Potential Participant
elects to
voluntarily reduce
Salary to
which
a
notice
received
under
Section
2(b)
pertains
and
receive
an
Award
hereunder
in
lieu
thereof,
the
Potential
Participant
must
make
an
election,
using
the Election
Form or
in such
other manner
prescribed by
the Plan
Administrator,
which must be received on or before
December 31 (or such earlier time as
may be
prescribed by
the
Plan Administrator)
prior to
the
beginning of
the
Plan Year
of
the
elected
deferral.
Such
election
must
be
in
writing
signed
by
the
Potential
Participant
and
must
state
the
amount
of
the
salary
reduction
the
Potential
Participant
elects.
Such
election
becomes
irrevocable
on
December
31
prior
to
the
beginning
of
the
Plan
Year,
subject
to
the
provisions
Section
5(d).
If
an
election is not properly made and timely received, the Potential
Participant will be
deemed to have elected to receive and not to defer any such Salary.
(c)
Long-Term
Incentive
Plan.
If
a
Potential
Participant
elects
to
defer
under
this
Plan
all
or
any
part
of
the
Award
to
which
a
notice
received
under
Section
2(c)
pertains,
the
Potential
Participant
must
make
such
election,
using
the
Election
Form or
in such
other manner
prescribed by
the
Plan Administrator,
which must
be
received
on
or
before
December
31
of
the
year
in
which
said
Section
2(c)
notice
was
received
(or
at
such
earlier
time
as
may
be
prescribed
by
the
Plan
Exhibit 10.19.2
9
Administrator).
The
Potential
Participant's
election
shall
become
irrevocable
on
December 31
of the
year in
which said
Section 2(c)
notice was
received,
subject
to
the
provisions
Section
5(d).
If
an
election
is
not
properly
made
and
timely
received,
the
Potential
Participant will
be
deemed
to
have elected
to
receive
and
not to defer any such Long-Term Incentive Plan Award.
Section 4.
Deferred Compensation Accounts.
(a)
Credit for Deferral.
Amounts deferred pursuant to Section 3(a) will
be credited to
a Deferred
Compensation Account
for the
Participant for
the Plan
Year
in which
the
amounts
are
deferred
not
later
than
30
days
after
the
Settlement
Date
of
the
Incentive Compensation Plan.
Amounts
deferred
pursuant
to
other
provisions
of
this
Plan
shall
be
credited to a Deferred Compensation Account for the Participant for the Plan Year
in
which
such
amounts
are
deferred
not
later
than
30
days
after
the
date
the
Award or Salary would otherwise
be payable.
If
an
Award
in
the
form
of
Restricted
Stock
or
Restricted
Stock
Units
provides
that,
in
certain
instances
the
Restricted
Stock
or
Restricted
Stock
Units
shall
be
cancelled
and
a
market
value
in
lieu
thereof
be
credited
to
a
Deferred
Compensation Account for the Participant,
then the market value shall be
credited
to
a
Deferred
Compensation
Account
for
the
Participant
as
of
the
day
that
the
Award
in the form of Restricted
Stock or Restricted Stock Units
is cancelled.
For
Awards
deferred under Section 3(c), the market value of the underlying Restricted
Stock or
the shares
represented by
the Restricted
Stock units
under a
Long-Term
Incentive Plan shall be
the Fair Market Value
defined in the
agreement pertaining
to the Award
on the Settlement
Date of the
Award
(or if such
agreement does not
define
Fair
Market
Value,
then
the
definition
of
Fair
Market
Value
under
the
Omnibus
Securities
Plan
under
which
the
Award
was
made
shall
be
used).
For
other Awards,
following shall apply:
(1)
The
market
value
of
the
underlying
Restricted
Stock
or
the
shares
represented
by
the
Restricted
Stock
Units
awarded
under
a
Long
Term
Exhibit 10.19.2
10
Incentive
Plan,
under
an
Incentive
Compensation
Plan
that
began
on
or
after
January
1,
2003,
under
an
Omnibus
Securities
Plan
(with
regard
to
awards
made
on
or
after
January
1,
2003),
and
for
the
Special
Stock
Awards
issued
on
October
22,
2002,
shall
be
the
monthly
average
Fair
Market Value
of the Stock during the calendar month
preceding the month
in which
the restrictions
lapse or
shares are
to be
delivered as
applicable.
The monthly average
Fair Market Value
of the Stock
is the average
of the
daily Fair Market Value
of the Stock for each trading day of the month.
(2)
For Awards
made prior
to those
times, the
market value of
the underlying
Restricted
Stock
or
the
shares
represented
by
the
Restricted
Stock
Units,
as
applicable,
shall
be
based
on
the
higher
of
(i)
the
average
of
the
high
and low selling
prices of the
Stock on the
date the restrictions
lapse or the
last
trading
day
before
the
day
the
restrictions
lapse
if
such
date
is
not
a
trading
day
or
(ii)
the
average
of
the
high
three
monthly
Fair
Market
Values
of
the
Stock
during
the
twelve
calendar
months
preceding
the
month in
which the
restrictions lapse.
The monthly
Fair Market
Value
of
the
Stock
is
the
average
of
the
daily
Fair
Market
Value
of
the
Stock
for
each trading
day of
the month.
The daily
Fair Market
Value
of the
Stock
shall be deemed
equal to
the average of
the high
and low selling
prices of
the Stock on the New York
Stock Exchange.
(b)
Designation
of
Investments.
The
amount
in
each
Deferred
Compensation
Account
of
a
Participant
shall
be
deemed
to
have
been
invested
and
reinvested
from time
to time,
in such
“eligible securities”
as the
Participant shall
designate.
Prior
to
or
in
the
absence
of
a
Participant’s
designation,
the
Company
shall
designate an “eligible security” in
which the Participant’s
Deferred Compensation
Account shall
be deemed
to have
been invested
until designation
instructions are
received
from
the
Participant.
Eligible
securities
are
those
securities
designated
by
the
Chief
Financial
Officer
of
ConocoPhillips,
or
his
successor.
The
Chief
Financial
Officer
of
ConocoPhillips
may
include
as
eligible
securities,
stocks
listed
on
a
national
securities
exchange,
and
bonds,
notes,
or
debentures,
corporate
or
governmental,
either
listed
on
a
national
securities
exchange
or
for
which price quotations are published in The Wall
Street Journal, and shares issued
Exhibit 10.19.2
11
by
investment
companies
commonly
known
as
“mutual
funds.”
The
Deferred
Compensation
Accounts
of
a
Participant
will
be
adjusted
to
reflect
the
deemed
gains,
losses,
earnings,
or
expenses
as
though
the
amount
deferred
was
actually
invested and
reinvested in
the eligible
securities for
each Deferred
Compensation
Account of the Participant.
Notwithstanding anything
to the contrary
in this
Section 4(b), in
the event
the Company (or any trust
maintained for this purpose) actually
purchases or sells
such
securities
in
the
quantities
and
at
the
times
the
securities
are
deemed
to
be
purchased
or
sold
for
a
Deferred
Compensation
Account
of
a
Participant,
the
Account shall be adjusted accordingly to reflect the price actually paid or received
by
the
Company
for
such
securities
after
adjustment
for
all
transaction
expenses
incurred (including without limitation brokerage fees and stock transfer taxes).
In
the
case
of
any
deemed
purchase
not
actually
made
by
the
Company,
the Deferred
Compensation Account
shall be
charged with
a dollar
amount equal
to
the
quantity
and
kind of
securities
deemed
to
have been
purchased
multiplied
by
the
fair
market
value
of
such
security
on
the
date
of
reference
and
shall
be
credited
with
the
quantity
and
kind
of
securities
so
deemed
to
have
been
purchased.
In the case of any deemed sale not actually made by the Company,
the
account shall
be charged
with the
quantity and
kind of
securities deemed
to have
been
sold
and
shall
be
credited
with
a
dollar
amount
equal
to
the
quantity
and
kind of securities deemed
to have been sold multiplied
by the fair market
value of
such
security
on
the
date
of
reference.
As
used
in
this
paragraph
“fair
market
value”
means
in
the
case
of
a
listed
security
the
closing
price
on
the
date
of
reference,
or
if
there
were
no
sales
on
such
date,
then
the
closing
price
on
the
nearest
preceding
day
on
which
there
were
such
sales,
and
in
the
case
of
an
unlisted
security
the
mean
between
the
bid
and
asked
prices
on
the
date
of
reference, or
if no
such prices
are available
for such
date, then
the mean
between
the
bid
and
asked
prices
to
the
nearest
preceding
day
for
which
such
prices
are
available.
(c)
Payments.
A Participant’s
Deferred Compensation Account
shall be debited
with
respect
to
payments
made
from
the
account
pursuant
to
this
Plan
as
of
the
date
such payments
are made
from the
account.
Payments shall
be made
on the
dates
Exhibit 10.19.2
12
specified
in
the
elections
of
the
Participant;
provided,
however,
that
the
Participant
shall
have
no
right
to
complain
or
make
a
claim
about
the
date
of
a
payment
if
such
payment
is
made
no
earlier
than
30
days
prior
to
the
specified
date
and
no
later
than
the
end
of
the
calendar
year
in
which
such
specified
date
falls
(or,
if
later,
by
the
15
th
day
of
the
third
calendar
month
following
the
specified date).
If any person to whom a payment is due hereunder is
under legal disability
as
determined
in
the
sole
discretion
of
the
Plan
Administrator,
the
Plan
Administrator
shall
have
the
power
to
cause
the
payment
due
such
person
to
be
made
to
such
person’s
guardian
or
other
legal
representative
for
the
person’s
benefit,
and
such
payment
shall
constitute
a
full
release
and
discharge
of
the
Company,
all members
of the
Controlled Group,
the Plan
Administrator,
and any
fiduciary of the Plan.
(d)
Statements.
At
least
one
time
per
year
the
Plan
Administrator
(or
a
third
party
acting for the Plan Administrator) will furnish each Participant a written statement
setting
forth
the
current
balance
in
the
Participant’s
Deferred
Compensation
Accounts, the amounts credited or debited to such
account since the last statement
and
the
payment
schedule
of
deferred
Awards,
and
deemed
gains,
losses,
earnings, or expenses accrued thereon as provided
by the deferred payment option
selected
by
the
Participant.
This
provision
shall
be
deemed
satisfied
if
the
Plan
Administrator
(or
a
third
party
acting
for
the
Plan
Administrator)
makes
such
information
available
through
electronic
means,
such
as
a
web
site,
and
informs
affected
Participants
of
the
availability
of
the
information
and
the
manner
of
accessing it.
Section 5.
Payments from Deferred Compensation Accounts.
(a)
Election
of
Method
of
Payment.
At
the
time
a
Potential
Participant
submits
an
election
to
defer
all
or
any
part
of
an
Award
under
an
Incentive
Compensation
Plan as provided
in Section 3(a) above
or to reduce
any part of salary
as provided
in Section
3(b) above
or to
defer all
or any
part of
an Award
under a
Long-Term
Incentive
Plan
as
provided
in
Section
3(c)
above,
the
Potential
Participant
shall
Exhibit 10.19.2
13
also elect, using the Election Form or
in such other manner prescribed by the
Plan
Administrator, which of the payment options, provided for in Paragraph (b) of this
Section,
shall
apply
to
the
deferred
portion
of
said
Award
or
salary
adjusted
for
any
deemed
gains,
losses,
earnings,
or
expenses
accrued
thereon
credited
to
the
Participant’s
Deferred
Compensation
Account
under
this
Plan.
Subject
to
Paragraph
(d)
of
this
Section,
the
election
of
the
method
of
payment
of
the
amount
deferred shall
become
irrevocable on
December
31
of
the
year
in
which
the applicable
Section 2(a),
(b), or
(c) notice
was
received (except
in the
case of
an
election
for
an
Award
under
an
Incentive
Compensation
Plan
determined
by
the
Plan
Administrator
to
be
“performance-based
compensation”
under
Code
section
409A,
the
election
shall
become
irrevocable
on
June
30
of
the
year
in
which
said
Section
2(a)
notice
was
received,
if
so
designated
by
the
Plan
Administrator).
If
an
election
does
not
properly
indicate
a
time
and
method
of
payment, the
Potential Participant
will be
deemed to
have elected
to receive
such
payment
in
a
single
lump
sum
at
the
earlier
of
death
or
the
first
of
the
calendar
quarter
that
is
(i)
with
regard
to
elections
made
before
January
1,
2020,
six
(6)
months
after
the
date
of
the
Participant’s
Separation
from
Service
and
(ii)
with
regard
to
elections
mad
after
December
31,
2019,
twelve
(12)
months
after
the
date of the Participant’s Separation from Service
other than by death.
(b)
Payment Options.
A Potential Participant may elect, using an Election
Form or in
such
other
manner
prescribed
by
the
Plan
Administrator,
to
have
the
deferred
portion of
an Incentive
Compensation Plan
Award
or salary
or an
Award
under a
Long-Term
Incentive
Plan,
described
in
Sections
3(a),
(b),
and
(c)
respectively
(adjusted
for
any
deemed
gains,
losses,
earnings,
or
expenses
accrued
thereon)
paid, provided
that, for
elections after
December 31,
2019, no
first payment
shall
commence later than the 100
th
birthday of the Participant:
(1)
(After Separation
from
Service)
in 1
to 15
annual installments,
in 2
to 30
semi-annual installments, or
in 4 to
60 quarterly installments,
the payment
of the first of
any of such installments
to commence on the
first day of the
first calendar
quarter which
is on
or
after
one year
from
the
Participant’s
Separation
from
Service
and
is
no
longer
than
five
years
from
the
Participant’s
Separation
from
Service,
subject
to
Paragraph
(d)
of
this
Exhibit 10.19.2
14
Section, or
(2)
(Date
Certain)
with
regard
only
to
the
deferred
portion
of
an
Incentive
Compensation Award
or
of salary
(but only
with respect
to salary
earned
on or after
January 1, 2015)
or of an
Award
under a
Long-Term
Incentive
Plan
(described
in
Sections
3(a),
(b),
and
(c)
respectively),
in
1
to
15
annual
installments,
in
2
to
30
semi-annual
installments,
or
in
4
to
60
quarterly installments, the
payment of the
first of
any of such
installments
to
commence
on
the
first
day
of
calendar
quarter
which
is
designated
by
the Participant,
is at
least one
year after
the date
on which
the election
is
made, subject to Paragraph (d) of this Section.
(3)
In the event that no election is properly and timely made with regard to the
time and method of payment under
Section 5(b)(i), payment shall be
made
on
the
earlier
of
the
death
or
the
date
which
is
the
first
of
the
calendar
quarter that is (i) with regard to elections
made before January 1, 2020, six
(6) months
after the
date of
the Participant’s
Separation from
Service and
(ii) twelve
(12) months
after the
date of
the Participant’s
Separation from
Service,
whether
by
retirement,
disability,
or
otherwise
(other
than
by
death), of the Participant, subject to Paragraph (d) of this Section.
A Potential Participant may elect, using an
Election Form or in such other
manner
prescribed
by
the
Plan
Administrator,
to
have
the
deferred
portion
of
a
Long-
Term
Incentive
Plan
Award
deferred
pursuant
to
Section
3(c)
(adjusted
for
any
deemed
gains,
losses,
earnings,
or
expenses
accrued
thereon)
paid
at
such
times
and in such manner as set forth on such Election Form, subject to Paragraph (d) of
this Section.
(c)
Method of Payment of the
Value
of Certain Restricted Stock
and Restricted Stock
Units.
If an Award
(other than an Award
deferred pursuant to Section 3(c))
in the
form
of
Restricted
Stock
or
Restricted
Stock
Units
provides
that
in
certain
instances the
Restricted
Stock or
Restricted Stock
Units shall
be cancelled
and a
market value
in lieu
thereof be
credited to
a Deferred
Compensation Account
for
the
Participant,
payment
of
such
Deferred Compensation
Account shall
be
made
on the earlier of the
death or the date which
is the first of
the calendar quarter that
is
(i)
with
regard
to
elections
made
before
January
1,
2020,
six
(6)
months
after
Exhibit 10.19.2
15
the
date
of
the
Participant’s
Separation
from
Service
and
(ii)
with
regard
to
elections
made
after
December
31,
2019,
twelve
(12)
months
after
the
date
of
Separation
from
Service,
whether
by
retirement,
disability,
or
otherwise
(than
death), of the Participant, subject to Paragraph (d) of this Section.
(d)
Change
in
Time
or
Form
of
Payment.
A
Participant
may
make
an
election
to
change the time
or form of
payment elected or
set under
Section 5 (including
this
Paragraph (d)), but only if the following rules are satisfied:
(1)
The
election
to
change
the
time
or
form
of
payment
may
not
take
effect
until at least twelve months after the date on which such election is made;
(2)
Except
for
a
payment
made
with
respect
to
the
death
of
the
Participant,
payment
under
such
election
may
not
be
made
earlier
than
at
least
five
years
from
the
date
the
payment
would
have
otherwise
been
made
or
commenced;
(3)
Such payment may commence as of the beginning of any calendar quarter;
(4)
An election to receive
payments in installments shall
be treated as a
single
payment for purposes of these rules;
(5)
The
election
may
not
result
in
an
impermissible
acceleration
of
payment
prohibited under Code section 409A;
(6)
No
more
than
three
(3)
such
elections
shall
be
permitted
with
respect
to
each Deferred Compensation Account of a Participant; and
(7)
For
changes
made
after
December
31,
2019,
no
first
payment
may
be
scheduled to commence after the 100
th
birthday of the Participant.
(e)
Effect
of
Taxation.
If
a
portion
of
a
Participant’s
Benefits
under
the
Plan
(and
gains,
losses,
earnings,
or
expenses
thereon)
is
includible
in
income
under
Code
section 409A, such portion shall be distributed immediately to the Participant.
(f)
Installment
Amount.
The
amount
of
each
installment
shall
be
determined
by
dividing
the
balance
in
the
Participant’s
Deferred
Compensation
Account
as
of
the date
the installment
is to
be paid,
by the
number of
installments remaining
to
be paid (inclusive of the current installment).
(g)
Death
of
Participant.
Upon
the
death
of
a
Participant,
the
Participant’s
Beneficiary
or
Beneficiaries
determined
in
accordance
with
Section
8.,
shall
receive
payments
in
accordance
with
the
payment
option
selected
by
the
Exhibit 10.19.2
16
Participant
or,
if
no
payment
option
was
properly
and
timely
selected
by
the
Participant
with
regard
to
a
Deferred
Compensation
Account,
upon
the
death
of
the Participant.
Section 6.
Special Provisions for Former ARCO Alaska Employees.
Notwithstanding any
provisions to
the contrary,
in order
to comply
with the
terms of
the
Master
Purchase
and
Sale
Agreement
(“Sale
Agreement”)
by
which
the
Company
acquired certain
Alaskan assets
of Atlantic
Richfield Company
(“ARCO”), a
Participant
who was eligible to participate in
the ARCO employee benefit plans immediately
prior to
becoming
an
Employee
and
who
was
not
employed
by
ARCO
Marine,
Inc.
(a
“former
ARCO Alaska
employee”) and
who was
classified
as a
grade 7
or 8
under ARCO’s
job
classification
system
and
was
eligible
under
ARCO’s
Executive
Deferral
Plan
to
voluntarily reduce salary
and defer the amount
of the voluntary salary
reduction and who
was
classified
as
a
grade
31
or
below
at
that
time
under
Phillips
Petroleum
Company’s
job classification system may,
in a manner prescribed by the Plan Administrator,
make an
election
to
voluntarily
reduce
salary
and
defer
the
amount
of
the
voluntary
salary
reduction for salary received
for 2005 and receive
a salary deferral credit
under this Plan;
provided, that
all of
the Plan
provisions (other
than eligibility
to participate)
shall apply
to such an election.
Section 7.
Schedule A Employees.
Notwithstanding
any
earlier
election
or
indication
of
preference
to
participate
in
voluntary salary reductions
to be deferred
into the
Plan in
2005 or deferrals
into the Plan
in 2005
of Awards
under an
Incentive Compensation
Plan, Schedule
A Employees
shall
have
their
participation
in
the
Plan
for
2005
revoked
as
to
the
salary
reductions
or
Incentive
Compensation
Plan
Award
or
both,
as
indicated
on
Schedule
A
to
this
Plan.
Any
such
deferrals
made
in
2005
for
such
Schedule
A
Employees
shall
be
returned
to
them
(together
with
any
gains,
losses,
earnings,
or
expenses
thereon)
on
or
before
December 31, 2005.
Exhibit 10.19.2
17
Section 8.
Beneficiary Designation.
A Participant
may
designate
a
Beneficiary
or
Beneficiaries
to receive
the
entire
balance
of
the
Participant’s
Deferred
Compensation
Account
by
giving
signed
written
notice
of
such designation
to the
Plan Administrator
upon forms
supplied by
and delivered
to the
Plan
Administrator
and
may
revoke
such
designations
in
writing;
provided,
that
writing
and
signing
may
be
done
by
any
electronic
means
approved
by
the
Plan
Administrator.
The
Participant
may
from
time
to
time
change
or
cancel
any
previous
beneficiary
designation
in
the
same
manner.
The
last
beneficiary
designation
received
by
the
Plan
Administrator shall
be controlling
over any
prior
designation and
over any
testamentary
or
other
disposition.
After
acceptance
by
the
Plan
Administrator
of
such
written
designation, it
shall take
effect as
of the
date on
which it
was signed
by the
Participant,
whether the
Participant is
living at
the time
of such
receipt, but
without prejudice
to the
Company
or
any
member
of
the
Controlled
Group
or
the
Plan
Administrator
or
their
respective employees and
agents on account of
any payment made
under this Plan
before
receipt
of
such
designation.
If
no
designation
of
a
Beneficiary
is
on
file
with
the
Plan
Administrator
at
the
time
of
the
death
of
the
Participant
or
such
designation
is
not
effective
for
any
reason
as
determined
by
the
Plan
Administrator,
then,
for
purposes
of
this
Plan,
“Beneficiary”
shall
mean,
and
such
Benefits
shall
be
paid
to,
(i)
the
Participant's
surviving
spouse
as
of
the
Participant's
date
of
death,
or
(ii)
if
there
is
no
surviving spouse as of the Participant's date of death, the Participant’s estate.
Section 9.
Acceleration of Payment of Benefits.
Notwithstanding
any
other
provision
of
this
Plan
to
the
contrary,
except
as
provided
in
Section 18(g) and below,
in no event shall this
Plan permit the acceleration
of the time or
schedule
of
any
payment
or
distribution
under
this
Plan,
except
that
the
Plan
Administrator may accelerate a
payment or distribution under
this Plan to
comply with a
certificate
of
divestiture,
as
provided
in
section
1.409A-3(j)(4)(iii)
of
the
Treasury
regulations.
Moreover,
if
a
portion
of
a
Participant's
Benefit
(and
earnings,
gains,
and
losses thereon)
is includible
in income
under Code
section 409A,
then such
portion shall
Exhibit 10.19.2
18
be
distributed
immediately
to
the
Participant
in
accordance
with
section
1.409A-
3(j)(4)(vii) of the Treasury regulations.
Section 10.
Nonassignability.
The
interest
of
a
Participant
or
his
Beneficiary
or
Beneficiaries
hereunder
may
not
be
sold,
transferred,
assigned,
or
encumbered
in
any
manner,
either
voluntarily
or
involuntarily,
and
any
attempt
so
to
anticipate,
alienate,
sell,
transfer,
assign,
pledge,
encumber, or
charge the
same shall be null
and void; neither
shall the Benefits
hereunder
be
liable
for
or
subject
to
the
debts,
contracts,
liabilities,
engagements,
or
torts
of
any
person
to
whom
such
Benefits
or
funds
are
payable,
nor
shall
they
be
an
asset
in
bankruptcy or subject to garnishment, attachment, or other legal or equitable proceedings.
Section 11.
Administration.
(a)
The
Plan
shall
be
administered
by
the
Plan
Administrator.
The
Plan
Administrator may
delegate to
employees of
the Company
or any
member of
the
Controlled
Group
the
authority
to
execute
and
deliver
such
instruments
and
documents,
to
do
all
such
acts
and
things,
and
to
take
such
other
steps
deemed
necessary,
advisable, or
convenient for
the effective
administration of
the Plan
in
accordance
with
its
terms
and
purpose,
except
that
the
Plan
Administrator
may
not
delegate
any
discretionary
authority
with
respect
to
substantive
decisions
or
functions regarding
the Plan
or Benefits
under the
Plan.
The Plan
Administrator
may designate
a third
party to
provide services
that may
include record
keeping,
Participant accounting, Participant communication, payment of installments
to the
Participant,
tax
reporting,
and
any
other
services
specified
in
an
agreement
with
such third
party.
The Plan
Administrator may
adopt such
rules, regulations,
and
forms
as
deemed
desirable
for
administration
of
the
Plan
and
shall
have
the
discretionary
authority
to
allocate
responsibilities
under
the
Plan
to
such
other
persons
as
may
be
designated.
The
Plan
Administrator
shall
have
absolute
discretion
in
carrying
out
its
responsibilities,
and
all
interpretations,
findings
of
fact
and
resolutions
described
herein
which
are
made
by
the
Plan
Administrator
Exhibit 10.19.2
19
shall be binding, final and conclusive on all parties.
(b)
The
Plan
Administrator
and
his
or
her
delegates
shall
serve
without
bond
and
without
compensation
for
services
under
this
Plan.
All
expenses
of
the
Plan
Administrator and his or her delegates for services under this Plan shall be paid by
the
Company.
None
of
the
Plan
Administrator
or
his
or
her
delegates
shall
be
liable
for
any
act
or
omission
on
his
or
her
own
part
excepting
his
or
her
own
willful
misconduct.
Without
limiting
the
generality
of
the
foregoing,
any
such
decision
or
action
taken
by
the
Plan
Administrator
or
his
or
her
delegates
in
reliance
upon
any
information
supplied
by
an
officer
of
the
Company,
the
Company's
legal
counsel,
or
the
Company's
independent
accountants
in
connection
with
the
administration
of
this
Plan
shall
be
deemed
to
have
been
taken in good faith.
Section 11.1
Claim for Benefits.
(a)
Any
claim
for
benefits
hereunder
shall
be
presented
in
writing
to
the
Plan
Administrator
for
consideration,
grant,
or
denial.
Claimants
will
be
notified
in
writing
of
approved
claims,
which
will
be
processed
as
claimed.
A
claim
is
considered
approved
only
if
its
approval
is
communicated
in
writing
to
a
claimant.
(b)
In the
case of
a denial
of a
claim respecting
benefits paid
or payable
with respect
to
a
Participant,
a
written
notice
will
be
furnished
to
the
claimant
within
ninety
(90) days of the date
on which the claim is
received by the Plan
Administrator.
If
special circumstances (such
as for a hearing)
require a longer
period, the claimant
will be notified in
writing, prior to the
expiration of the ninety
(90)-day period, of
the
reasons
for
an
extension
of
time;
provided,
however,
that
no
extensions
will
be permitted beyond ninety (90) days after the expiration of the initial ninety (90)-
day period.
A denial
or partial
denial of
a claim
will be
dated and
signed by
the
Plan Administrator and will clearly set forth:
(1)
the specific reason or reasons for the denial;
(2)
specific reference to pertinent Plan provisions on which the denial is
based;
Exhibit 10.19.2
20
(3)
a description of any additional material or information necessary for the
claimant to perfect the claim and an explanation of why such material or
information is necessary; and
(4)
an explanation of the procedure for review of the denied or partially
denied claim set forth below, including the claimant’s
right to bring a civil
action under ERISA section 502(a) following an adverse benefit
determination on review.
(c)
Upon
denial
of
a
claim,
in
whole
or
in
part,
a
claimant
or
his
duly
authorized
representative will
have the
right to
submit a
written request
to the
Trustee
for a
full and
fair
review of
the denied
claim by
filing
a written
notice
of
appeal
with
the Trustee
within sixty
(60) days
of the
receipt by
the claimant
of written
notice
of the denial
of the claim.
A claimant or
the claimant’s
authorized representative
will have, upon request and
free of charge, reasonable access
to, and copies of, all
documents,
records,
and
other
information
relevant
to
the
claimant’s
claim
for
benefits
and
may
submit
issues
and
comments
in
writing.
The
review
will
take
into
account all
comments,
documents,
records, and
other
information
submitted
by the
claimant relating
to the
claim, without
regard to
whether such
information
was
submitted
or
considered
in
the
initial
benefit
determination.
If the
claimant
fails to
file a
request for
review within
sixty
(60) days
of the
denial notification,
the claim
will be
deemed abandoned
and the
claimant precluded
from reasserting
it.
If
the
claimant
does
file
a
request
for
review,
his
request
must
include
a
description of
the issues
and evidence
he deems
relevant.
Failure to
raise issues
or present
evidence on
review will
preclude those
issues or
evidence from
being
presented in any subsequent proceeding or judicial review of the claim.
(d)
The
Trustee
will
provide
a
prompt
written
decision
on
review.
If
the
claim
is
denied on review, the decision shall set forth:
(1)
the specific reason or reasons for the adverse determination;
(2)
specific
reference
to
pertinent
Plan
provisions
on
which
the
adverse
determination is based;
(3)
a statement that the claimant is entitled to receive, upon request and free of
charge,
reasonable
access
to,
and
copies
of,
all
documents,
records,
and
other information relevant to the claimant’s claim for benefits; and
Exhibit 10.19.2
21
(4)
a
statement
describing
any
voluntary
appeal
procedures
offered
by
the
Plan
and
the
claimant’s
right
to
obtain
the
information
about
such
procedures, as well as a statement of the claimant’s
right to bring an action
under ERISA section 502(a).
(e)
A
decision
will
be
rendered
no
more
than
sixty
(60)
days
after
the
Trustee’s
receipt of
the request
for review,
except that
such period
may be
extended for
an
additional
sixty
(60)
days
if
the
Trustee
determines
that
special
circumstances
(such as for a hearing) require
such extension.
If an extension of time
is required,
written notice of
the extension
will be furnished
to the claimant
before the
end of
the initial sixty (60)-day period.
(f)
To
the extent permitted by
law, decisions
reached under the claims procedures
set
forth in
this Section
shall be
final and
binding on
all parties.
No legal
action for
benefits
under
the
Plan
shall
be
brought
unless
and
until
the
claimant
has
exhausted his
remedies under
this Section.
In any
such legal
action, the
claimant
may only
present evidence
and theories
which
the
claimant
presented during
the
claims procedure.
Any
claims which
the
claimant
does not
in good
faith
pursue
through
the
review
stage
of
the
procedure
shall
be
treated
as
having
been
irrevocably waived.
Judicial review
of a claimant’s
denied claim shall
be limited
to a
determination of
whether the
denial was
an abuse
of discretion
based on
the
evidence and theories the claimant presented during the claims procedure.
(g)
Any payment to a Participant or Beneficiary,
all in accordance with the provisions
of
this
Plan,
shall
to
the
extent
thereof
be
in
full
satisfaction
of
all
claims
hereunder
against
the
Plan
Administrator,
the
Company
and
all
Participating
Subsidiaries,
any
of
which
may
require
such
Participant
or
Beneficiary
as
a
condition to
such payment
to execute
a receipt
and
release therefor
in such
form
as shall be
determined by the
Plan Administrator,
the Company or
a Participating
Subsidiary.
If a
receipt and
release is
required and
the Participant
or Beneficiary
(as
applicable)
does
not
provide
such
receipt
and
release
in
a
timely
enough
manner
to
permit
a
timely
distribution
in
accordance
with
the
general
timing
of
distribution
provisions
in
this
Plan,
the
payment
of
any
affected
distribution(s)
shall be forfeited.
Exhibit 10.19.2
22
(h)
Benefits under
this Plan
will be
paid only
if the
Plan Administrator
decides in
its
discretion
that
a
Participant
or
Beneficiary
is
entitled
to
the
Benefits.
Notwithstanding
the
foregoing
or
any
provision
of
this
Plan,
a
Participant
(or
other claimant)
must exhaust
all administrative
remedies set
forth in
this
Section
11.1
or
otherwise
established
by
the
Plan
Administrator
before
bringing
any
action
at
law
or
equity.
Any
claim
based on
a
denial of
a
claim
under this
Plan
must be brought
no later
than the date
which is two
(2) years after
the date
of the
final denial of a claim under this Section 11.1.
Any claim not brought within such
time shall be waived and forever barred.
Section 12.
Rights of Employees and Participants.
Nothing
contained in
the
Plan
(or
in
any
other
documents
related
to
this
Plan
or
to
any
Benefit
under
the
Plan)
shall
confer
upon
any
Employee
or
Participant
any
right
to
continue in the employ or
other service of the Company
or any member of the
Controlled
Group
or
constitute
any
contract
or
limit
in
any
way
the
right
of
the
Company
or
any
member of
the Controlled
Group to
change such
person's compensation
or other
benefits
or position or to terminate the employment of such person with or without cause.
Section 13.
Determination of Recipients of Awards.
The
determination
of
those
persons
who
are
entitled
to
Awards
under
an
Incentive
Compensation
Plan
and any
other
such
plans
shall
be
governed solely
by
the
terms
and
provisions
of
the
applicable
plan
or
program,
and
the
selection
of
an
Employee
as
a
Potential
Participant or
the
acceptance
of
an indication
of
preference to
defer
an
Award
hereunder shall not in any way entitle such Potential Participant to an Award.
Section 14.
Awards in Foreign
Countries.
The
Board
or
its
delegate
shall
have
the
authority
to
adopt
such
modifications,
procedures, and
subplans as
may be
necessary or
desirable to
comply with
provisions of
the
laws
of
foreign
countries
in
which
the
Company
or
Participating
Subsidiaries
may
Exhibit 10.19.2
23
operate to
assure the
viability of
the Benefits
of Participants
employed in
such countries
and to meet the purpose of this Plan.
Section 15.
Amendment and Termination.
The Board reserves
the right
to amend this
Plan from time
to time,
to terminate this
Plan
entirely
at
any
time,
and
to
delegate
such
authority
as
the
Board
deems
necessary
or
desirable;
provided,
however,
that
no
amendment
may
affect
the
balance
in
a
Participant’s
account on
the effective
date
of
the
amendment; and,
further
provided, the
Company shall remain
liable for any
Benefits accrued under
this Plan prior
to the date
of
amendment or termination.
Section 16.
Method of Providing Payments.
(a)
Nonsegregation.
Amounts
deferred
pursuant
to
this
Plan
and
the
crediting
of
amounts
to
a
Participant’s
Deferred
Compensation
Accounts
shall
represent
the
Company’s
unfunded
and
unsecured
promise
to
pay
compensation
in
the
future.
With
respect to
said
amounts,
the
relationship
of the
Company
and
a
Participant
shall be
that of
debtor and
general unsecured
creditor.
While the
Company may
make investments for
the purpose of
measuring and meeting
its obligations under
this Plan
such investments shall
remain the sole
property of
the Company
subject
to claims of its creditors generally, and shall not be deemed to form or be included
in any part of the Deferred Compensation Accounts.
(b)
Funding.
It is
the intention
of the
Company that
this
Plan shall
be unfunded
for
federal tax
purposes and
for purposes
of Title
I of
ERISA.
All amounts
payable
under this
Plan
shall
be paid
solely
from
the
general assets
of
the
Company
and
any
rights
accruing
to
a
Participant
under
this
Plan
shall
be
those
of
a
general
creditor; provided, however,
that the Company
may establish one
or more grantor
trusts to
satisfy part
or all
of the
Company's Plan
payment obligations
so long
as
this
Plan
remains
unfunded
for
purposes
of
sections
201(2),
301(a)(3),
and
401(a)(1) of ERISA.
Exhibit 10.19.2
24
Section 17.
Miscellaneous Provisions.
(a)
Except
as
otherwise
provided
herein,
the
Plan
shall
be
binding
upon
the
Company,
its successors and
assigns, including but
not limited to
any corporation
which may acquire all or substantially all of the Company’s
assets and business or
with or into which the Company may be consolidated or merged.
(b)
This Plan
shall be
construed, regulated,
and administered
in
accordance with
the
laws of the State of Texas
except to the extent that said laws have been preempted
by
the
laws
of
the
United
States.
The
forum
and
venue
for
any
suit
brought
regarding any claim under this Plan shall be in Harris County, Texas.
(c)
If
any
provision
of
this
Plan
shall
be
held
illegal
or
invalid
for
any
reason,
said
illegality
or
invalidity
shall
not
affect
the
remaining
provisions
hereof;
instead,
each
provision
shall
be
fully
severable,
and
this
Plan
shall
be
construed
and
enforced as if said illegal or invalid provision had never been included herein.
(d)
For
purposes
of
this
Plan,
electronic
communications
and
signatures
shall
be
considered to be
in writing if
made in conformity
with procedures which
the Plan
Administrator may adopt from time to time.
(e)
The
Plan
Administrator,
in
its
sole
discretion,
may
direct
that
a
payment
to
be
made
to
an
incompetent
or
disabled
person,
whether
because
of
minority
or
mental
or
physical
disability,
instead
be
made
to
the
guardian
or
legal
representative
of
such
person
or
to
the
person
having
custody
of
such
person
(unless prior
claim therefor
shall have
been made
by a
duly qualified
guardian or
other
legal
representative),
without
further
liability
either
on
the
part
of
the
Company
or
a
Participating
Subsidiary
or
the
Plan
for
the
amount
of
such
payment
to
the
person
on
whose
benefit
such
payment
is
made.
Any
payment
made
in
accordance
with
the
provisions
of
this
provision
shall
be
a
complete
discharge
of
any
liability
of
the
Company,
its
Subsidiaries,
and
this
Plan
with
respect to the Benefits so paid.
(f)
Payment
of
Plan
Benefits
may
be
subject
to
administrative
or
other
delays
that
result
in
payment
to
the
Participant
or
his
beneficiaries
on
a
date
later
than
the
date specified
in this
Plan or
the Participant's
Election Form.
Any such
payment
delays
will
comply
with
Code
section
409A
of
the
Code,
including
without
Exhibit 10.19.2
25
limitation
section
1.409A-2(b)(7)
of
the
Treasury
regulations.
No
Participant
or
Beneficiary
shall
be
entitled
to
any
additional
earnings
or
interest
in
respect
of
any such payment delays, nor shall any Participant or Beneficiary be provided any
election with respect to the timing of any delayed payment.
(g)
If
all
or
any
part
of
any
Participant's
or
Beneficiary's
Benefits
hereunder
shall
become subject to any estate, inheritance, income, employment
or other tax which
the
Company
shall
be
required
to
pay
or
withhold,
the
Company
shall
have
the
full power
and authority
to withhold
and pay
such tax
out of
any monies
or other
property
held
for
the
account
of
the
Participant
or
Beneficiary
whose
interests
hereunder
are
so
affected
(including,
without
limitation,
by
reducing
and
offsetting the Participant's or
Beneficiary's account balance).
Prior to making any
payment,
the
Company
may
require
such
releases
or
other
documents
from
any
lawful taxing authority as it shall deem necessary or desirable.
(h)
No
amount
accrued
or
payable
hereunder
shall
be
deemed
to
be
a
portion
of
an
Employee's
compensation
or
earnings
for
the
purpose
of
any
other
employee
benefit
plan
adopted
or
maintained
by
the
Company,
nor
shall
this
Plan
be
deemed to amend or modify the provisions of the CPSP.
(i)
It is
the intention
of the
Company that,
so long
as any
of ConocoPhillips
’
equity
securities
are
registered
pursuant
to
section
12(b)
or
12(g)
of
the
Exchange
Act,
this Plan
shall be
operated in
compliance with
16(b) of
the Exchange
Act and,
if
any Plan provision
or transaction is found
not to comply
with section 16(b)
of the
Exchange Act,
that provision
or transaction,
as the
case may
be, shall
be deemed
null and void
ab initio
.
Notwithstanding anything
in the Plan
to the
contrary,
the
Company,
in its
absolute discretion,
may bifurcate
the Plan
so as
to restrict,
limit
or condition
the use
of any
provision of
the Plan
to Participants
who are
officers
and directors
subject to
section 16(b)
of the
Exchange Act
without so
restricting,
limiting, or conditioning the Plan with respect to other Participants.
(j)
This
Plan
is
intended
to
meet
the
requirements
of
Code
section
409А,
as
applicable,
in
order
to
avoid
any
adverse
tax
consequences
resulting
from
any
failure
to
comply
with
Code
section
409А
and,
as
a
result,
this
Plan
shall
be
operated
in
a
manner
consistent
with
such
compliance.
Except
to
the
extent
expressly
set
forth
in
this
Plan,
the
Participant
(and/or
the
Participant's
Exhibit 10.19.2
26
Beneficiary,
as applicable) shall
have no right
to dictate the
taxable year in
which
any payment hereunder that is subject to Code section 409А should be paid.
(k)
This
Title
II
replaced
Title
I
of
the
Plan,
which
was
frozen
effective
as
of
December
31,
2004.
The
distribution
of
amounts
that
were
earned
and
vested
(within
the
meaning
of
Code
section
409A
and
official
guidance
issued
thereunder)
under
Title
I
of
the
Plan
prior
to
January
1,
2005
(and
earnings
thereon) are exempt from the requirements of Code section 409A shall be
made in
accordance with the terms of the Title I of the Plan.
(l)
At the Effective
Time, certain
active employees of
Phillips 66 and
members of its
controlled
group
ceased
to
participate
in
the
Plan,
and
the
liabilities,
including
liabilities related to
benefits grandfathered from Code
section 409A (
i.e.
, amounts
deferred
and
vested
prior
to
January
1,
2005),
for
these
participant's
benefits
under the Plan were transferred to the members of the Phillips 66 controlled group
and
continued
as
the
Phillips
66
Key
Employee
Deferred
Compensation
Plan.
ConocoPhillips
distributed
its
interest
in
Phillips
66
to
its
shareholders
as
of
the
Distribution.
On
and
after
the
Effective
Time,
the
Company,
ConocoPhillips,
other members of the
Controlled Group (as determined
after the Distribution), the
Plan,
any
directors,
officers,
or
employees
of
any
member
of
the
Controlled
Group
(as
determined
after
the
Distribution),
and
any
successors
thereto,
shall
have no further obligation or liability to, or on
behalf of, any such participant with
respect to any
benefit, amount,
or right transferred
to or due
under the Phillips
66
Key Employee Deferred Compensation Plan.
Further,
as
of
the
Distribution,
any
Phillips
66
common
stock
("Phillips
66
Stock")
held
in
the
Company
Stock
Fund
shall
be
transferred
to
a
separate
Investment
Option
under
this
Plan
that
is
accounted
for
as
if
investments
were
made
in
Phillips
66
Stock,
although
no
such
actual
investments
need
be
made,
with
accounting
entries
being
sufficient
therefor.
Investments
in
the
Phillips
66
Stock
fund
will
be
determined
as
of
the
Distribution.
On
and
after
the
Distribution, a
Participant will
be allowed
to hold
or liquidate
his or
her deemed
investment in Phillips
66 Stock.
No additional deemed investments
in Phillips 66
Stock will be allowed to be elected.
Further still,
as of
the Distribution,
the Restricted
Stock and
Restricted Stock
Exhibit 10.19.2
27
Units
of
ConocoPhillips
shall
be
converted
into
Restricted
Stock
and
Restricted
Stock
Units
of
ConocoPhillips
and
restricted
stock
and
restricted
stock
units
of
Phillips
66
as
provided
in
the
Agreement.
The
amounts
to
be
credited
to
a
Participant's Deferred Compensation Account under
Section 4(a) will be
based on
such Restricted Stock and
Restricted Stock Units of
ConocoPhillips and restricted
stock and restricted stock units of Phillips 66 after the Distribution.
Furthermore,
with
regard
to
any
valuation
that
occurs
after
the
Distribution
and
which
requires
valuation
of
Stock
or
the
common
stock
of
Phillips
66
("Phillips
66
Common
Stock"),
or
of
both,
from
a
time
on
or
before
the
Distribution and from a time
after the Distribution, then the
following shall apply,
in
order
to
allow
the
valuation
to
take
into
account
the
distribution
by
stock
dividend of one
share of
Phillips 66
Common Stock for
each two
shares of
Stock
held at the Distribution:
(1)
The value
of Stock
or of
Phillips 66
Common Stock determined
as of
any
date
after
the
Distribution
shall
be
determined
using
market
information
related to each;
(2)
The value of Stock determined as
of any date on or before the
Distribution
that
does
not
also
require
a
valuation
of
Stock
as
of
any
date
after
the
Distribution shall be determined using
market information related to Stock
as it traded on or before the Distribution;
(3)
The value of Stock determined
as of any date on or
before the Distribution
that also
requires a
valuation of
Stock or
of Phillips
66 Common
Stock as
of any
date
after the
Distribution
shall be
deemed
to be
two-thirds
of
the
value of
Stock determined
using market
information related
to Stock
as it
traded on or before the Distribution; and
(4)
The value
of Phillips
66 Common
Stock determined
as of
any date
on or
before the Distribution that also requires a valuation of Stock or of Phillips
66 Common Stock
as of any date
after the Distribution
shall be deemed to
be
one-third
of
the
value
of
Stock
determined
using
market
information
related to Stock as it traded on or before the Distribution.
Exhibit 10.19.2
28
Section 18.
Effective Date of the Restated Plan.
Title
II
of
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips
is
hereby
amended and
restated as
set forth
in this
2020 Amendment
and Restatement
effective as
of January 1, 2020.
Executed this ____ day of December, 2019, by a duly authorized officer of the Company.
Heather G. Sirdashney
Vice President, Human Resources
KEDCP Title II 2020 Restatement
12-19-2019
Exhibit 10.19.2
29
APPENDIX A
SELECT NEW HIRES TO
TITLE II OF
THE KEY EMPLOYEE DEFERRED COMEPNSATION
PLAN OF
CONOCOPHILLIPS
For Select New Hires, as set forth in resolutions adopted from time to time by the Human
Resources and Compensation
Committee of the
Board of Directors of
ConocoPhillips, or
its successor, the following provisions apply:
1.
The
Select
New
Hire
will,
effective
on
the
first
day
of
employment
with
the
Controlled
Group,
become
a
Participant
in
Title
II
of
the
Key
Employee
Deferred
Compensation
Plan
of
ConocoPhillips.
A
Deferred
Compensation
Account
will
be
created
for
the
Select
New
Hire
in
the
Plan.
The
amount
set
forth
in
the
applicable
resolution
will
be
credited
to
the
Deferred
Compensation
Account
for
the
Select
New
Hire
not
later
than
30
days
after
the
first
day
of
employment
of
the
Select
New
Hire.
Section 5(a)
of the
Plan shall
be disregarded
with respect
to the
Deferred Compensation
Account, and in lieu thereof
the Select New Hire
shall be asked to complete
and return to
the Plan Administrator election
forms to set the
time and form of
distribution with regard
to
the
Deferred
Compensation
Account
either
before
the
first
day
of
employment
or
no
later than 30 days after t
he first day of employment.
Other than with regard to the
timing
of the initial distribution election (as set
forth in the preceding sentence), other provisions
of
Section
5
of
the
Plan
shall
apply
to
the
Deferred
Compensation
Account,
including
default provisions in
the event that a
properly completed initial
distribution election form
is
not
received
within
the
time
set
forth
in
the
preceding
sentence.
For
purposes
of
Section
5(b)(ii)
of
the
Plan,
the
amount
set
forth
in
the
applicable
resolution
shall
be
considered to be a deferred portion of an Incentive Compensation Plan award.
Exhibit 10.19.2
30
2.
The
resolution
granting
participation
to
the
Select
New
Hire
will
also
set
the
vesting schedule for the
Deferred Compensation Account provided
pursuant to paragraph
1 of this Appendix.
3.
All other provisions of the Plan will
apply to the Deferred Compensation
Account
and the Select New Hire as a Participant in the Plan.
4.
Nothing
in
this
Appendix
is
intended
to
affect
the
other
operations
of
the
Plan,
such as
Salary reductions
and deferrals
or Incentive
Compensation Plan
deferrals.
If the
Select New
Hire is,
under the
provisions of
the Plan,
otherwise eligible
to, participate
in
the Plan, the Select New Hire may do so in accordance with those provisions.
Exhibit 10.19.2
31
SCHEDULE A
TO TITLE II OF THE
KEY EMPLOYEE DEFERRED COMPENSATION PLAN OF
CONOCOPHILLIPS
For Schedule A Employees, as defined in Title II of the Key Employee Deferred
Compensation Plan of ConocoPhillips, the following table shows the Employee Number,
Name of the Employee, and whether the Employee revoked salary deferral or Incentive
Compensation Plan Award
deferral or both with regard to deferrals made in 2005:
Employee
Number
Employee
Revoke
Salary
Deferral
Revoke Incentive
Compensation Plan
Deferral
012851
Farace, Sam A.
Yes
Yes
031006
Readal, Thomas C.
Yes
Yes
123415
Harpole, Kenneth J.
Yes
Yes
276875
Flesher, Robert G.
Yes
Yes
374304
Haynes, Thomas E.
No
Yes
494503
Halter, Donald J.
No
Yes
812045
Smith, Robert L.
Yes
Yes
867263
Fuhr, Kris J.
No
Yes
872498
Thompson, David A.
Yes
Yes
EX-10.27
Exhibit 10.27
1
FIRST AMENDMENT TO
ANNEX TO
NONQUALIFIED DEFERRED COMPENSATION ARRANGEMENTS
OF
CONOCOPHILLIPS
Effective as
of the
"Effective Time"
defined in
the Employee
Matters Agreement
by
and
between
ConocoPhillips
and
Phillips
66
(the
"Effective
Time"),
ConocoPhillips
Company
(the
“Company”)
amended
and
restated
the
Annex
to
Nonqualified
Deferred
Compensation
Arrangements
of
ConocoPhillips
(the
“409A
Annex”)
for
the
benefit
of
certain employees of the Company and its affiliates.
The Company desires to
amend the 409A Annex
by the revisions
set forth below,
effective upon the date of execution set forth below:
1.
Section 6 is hereby amended to revise the nomenclature of the existing provision
so that the existing paragraph now becomes paragraph (a).
2.
Section 6 is hereby further amended to add the following at the end thereof:
“(b)
In the
event that
an Employee
who is
a taxpayer
subject to
the Code
is a
Participant
in
an
International
NQDC
Arrangement,
then,
to
the
extent
that
no
exceptions
or
exclusions
apply
to
prevent
taxation
pursuant
to
section
409A
of
the
Code of
the benefits
under that
International NQDC
Arrangement, no
election, other
than
an
initial
deferral
election
that
satisfies
the
requirements
of
section
409A(a)(4)(B) of
the
Code
and
the
related Treasury
regulations
(an “Initial
Deferral
Election”), made by a Participant with
regard to an International NQDC Arrangement
shall
be
considered
or
made
effective,
and
the
terms
of
the
International
NQDC
Arrangement as to time and form of payment in the event of
no other election shall be
deemed to be the effective
time and form of payment.
If such an Employee makes an
Initial
Deferral
Election,
the
time
and
form
of
payment
specified
in
the
Initial
Deferral Election shall be the effective time and form of payment.
(c)
Notwithstanding
anything in
Section 6(b)
to the
contrary,
an Employee
who is
a
taxpayer
subject
to
the
Code
and
who
is
a
Participant
in
an
International
NQDC
Arrangement
may
make
an
election
to
change
the
time
or
form
of
payment
of
the
Initial Deferral Election, but only if the following rules are satisfied:
i.
The election
to change
the time
or form
of payment
may not
take effect
until
at least twelve months after the date on which such election is made;
ii.
Payment under
such election
may not
be made
earlier than
at least
five years
from the date the payment would have otherwise been made or commenced;
iii.
Such payment may commence as of the beginning of any calendar quarter;
iv.
An
election
to
receive
payments
in
installments
shall
be
treated
as
a
single
payment for purposes of these rules;
v.
The
election
may
not
result
in
an
impermissible
acceleration
of
payment
prohibited under section 409A of the Internal Revenue Code;
vi.
No more than one such election shall be permitted; and
Exhibit 10.27
2
vii. No payment may
be made
after the
date that
is six
(6) years
after the
date of
the Employee’s Separation from Service.”
Executed December 20, 2019.
For ConocoPhillips Company
________________________________
Heather G. Sirdashney
Vice President, Human Resources
EX-21
1
Exhibit 21
SUBSIDIARY LISTING OF CONOCOPHILLIPS
Listed below are subsidiaries of the registrant
at December 31, 2019.
Certain subsidiaries are omitted
since such companies considered in the aggregate
do not constitute a significant subsidiary.
Company Name
Incorporation
Location
Ashford Energy Capital Limited
Cayman Islands
BROG LP LLC
Delaware
Burlington Resources International Inc.
Delaware
Burlington Resources LLC
Delaware
Burlington Resources Offshore Inc.
Delaware
Burlington Resources Oil & Gas Company LP
Delaware
Burlington Resources Trading LLC
Delaware
Conoco Development Services Inc.
Delaware
Conoco Funding Company
Nova Scotia
Conoco Petroleum Operations Inc.
Delaware
ConocoPhillips (03-12) Pty Ltd
Victoria
ConocoPhillips (Browse Basin) Pty Ltd
Western Australia
ConocoPhillips (Grissik) Ltd.
Bermuda
ConocoPhillips (U.K.) Holdings Limited
United Kingdom
ConocoPhillips (U.K.) Marketing and Trading Limited
United Kingdom
ConocoPhillips Alaska II, Inc.
Delaware
ConocoPhillips Alaska, Inc.
Delaware
ConocoPhillips Angola 36 Ltd.
Cayman Islands
ConocoPhillips Angola 37 Ltd.
Cayman Islands
ConocoPhillips ANS Marketing Company
Delaware
ConocoPhillips Asia Ventures Pte. Ltd.
Singapore
ConocoPhillips Australia Barossa Pty Ltd
Western Australia
ConocoPhillips Australia Gas Holdings Pty Ltd
Western Australia
ConocoPhillips Australia Holdings Pty Ltd
Australia
ConocoPhillips Australia Investments Pty Ltd
Australia
ConocoPhillips Australia Pacific LNG Pty Ltd
Western Australia
ConocoPhillips Australia Pty Ltd
Western Australia
ConocoPhillips Bohai Limited
Bahamas
ConocoPhillips Canada (BRC) Partnership
Alberta
ConocoPhillips Canada (NS) 2426 ULC
Alberta
ConocoPhillips Canada Marketing & Trading ULC
Alberta
ConocoPhillips Canada NS Partnership
Alberta
ConocoPhillips Canada Resources Corp.
Alberta
ConocoPhillips China Inc.
Liberia
ConocoPhillips Colombia Ventures Ltd.
Cayman Islands
ConocoPhillips Company
Delaware
ConocoPhillips Funding Ltd.
Bermuda
ConocoPhillips Gulf of Paria B.V.
Netherlands
2
Company Name
Incorporation
Location
ConocoPhillips Hamaca B.V.
Netherlands
ConocoPhillips Indonesia Holding Ltd.
British Virgin Islands
ConocoPhillips JPDA Pty Ltd
Western Australia
ConocoPhillips Libya Waha Ltd.
Cayman Islands
ConocoPhillips Marine Containment Holdings
LLC
Delaware
ConocoPhillips Norge
Delaware
ConocoPhillips North Caspian Ltd.
Liberia
ConocoPhillips Norway Funding Ltd.
Bermuda
ConocoPhillips Petroleum Holdings B.V.
Netherlands
ConocoPhillips Pipeline Australia Pty Ltd
Western Australia
ConocoPhillips Qatar Funding Ltd.
Cayman Islands
ConocoPhillips Qatar Ltd.
Cayman Islands
ConocoPhillips Sabah Gas Holdings Limited
Cayman Islands
ConocoPhillips Sabah Gas Ltd.
Cayman Islands
ConocoPhillips Sabah Holdings Limited
Cayman Islands
ConocoPhillips Sabah Ltd.
Bermuda
ConocoPhillips Skandinavia AS
Norway
ConocoPhillips Surmont Partnership
Alberta
ConocoPhillips Transportation Alaska, Inc.
Delaware
ConocoPhillips WA-248 Pty Ltd
Western Australia
Darwin LNG Pty Ltd
Western Australia
Inexco Oil Company
Delaware
Phillips Coal Company
Nevada
Phillips International Investments, Inc.
Delaware
Phillips Investment Company LLC
Nevada
Phillips Petroleum International Corporation
LLC
Delaware
Phillips Petroleum International Investment Company
LLC
Delaware
Polar Tankers, Inc.
Delaware
Sooner Insurance Company
Vermont
The Louisiana Land and Exploration Company
LLC
Maryland
EX-23.1
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
We consent to the incorporation by reference of our reports dated
February 18, 2020
, with respect
to the consolidated financial statements, condensed consolidating financial
information, and
financial statement schedule of ConocoPhillips, and the effectiveness of internal control over
financial reporting of ConocoPhillips, included in this Annual Report
(Form 10-K) for the year
ended December 31,
2019
, in the following registration statements and related prospectuses.
ConocoPhillips
Form S-3
File No. 333-220845
ConocoPhillips
Form S-4
File No. 333-130967
ConocoPhillips
Form S-8
File No. 333-98681
ConocoPhillips
Form S-8
File No. 333-116216
ConocoPhillips
Form S-8
File No. 333-133101
ConocoPhillips
Form S-8
File No. 333-159318
ConocoPhillips
Form S-8
File No. 333-171047
ConocoPhillips
Form S-8
File No. 333-174479
ConocoPhillips
Form S-8
File No. 333-196349
ConocoPhillips
Form S-8
File No. 333-130967
/s/ Ernst & Young LLP
Houston, Texas
February 18, 2020
EX-23.2
Exhibit 23.2
DeGolyer
and
MacNaughton
5001
Spring
Valley
Road
Suite
800
Eas
t
Dallas,
Texas
75244
February 18, 2020
ConocoPhillips
925 N. Eldridge Parkway
Houston, Texas 77079
Ladies and Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton,
to
references to DeGolyer and MacNaughton as an independent
petroleum engineering
consulting firm in ConocoPhillips’ Annual Report on Form
10-K for the year ended
December 31, 2019, under the “Part II” heading “Item 8. Financial
Statements and
Supplementary Data” and subheading “Reserves Governance”
and under the “Part
IV” heading “Item 15. Exhibits, Financial Statement Schedules”
and subheading
“Index to Exhibits,” and to the inclusion of our process review
letter report dated
February 18, 2020 (our Report), as an exhibit to ConocoPhillips’
Annual Report on
Form 10-K for the year ended December 31, 2019. We also
consent to the
incorporation by reference of our Report in the Registration
Statements filed by
ConocoPhillips on Form S-3 (File No. 333-220845), Form S-4
(File No. 333-130967),
and Form S-8 (File Nos. 333-98681, 333 116216, 333-133101, 333-159318,
333
171047, 333-174479, 333-196349, and 333-130967).
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
EX-31.1
Exhibit 31.1
CERTIFICATION
I, Ryan M. Lance, certify that:
1.
I have reviewed this annual report on Form
10-K
of ConocoPhillips;
2.
Based on my knowledge, this report does not contain
any untrue statement of a material fact or omit
to
state a material fact necessary to make the statements
made, in light of the circumstances under
which
such statements were made, not misleading with
respect to the period covered by this
report;
3.
Based on my knowledge, the financial statements,
and other financial information included in this
report,
fairly present in all material respects the financial
condition, results of operations and cash
flows of the
registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing
and maintaining disclosure
controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the registrant
and
have:
(a)
Designed such disclosure controls and procedures,
or caused such disclosure controls
and
procedures to be designed under our supervision,
to ensure that material information relating
to the
registrant, including its consolidated subsidiaries,
is made known to us by others within those
entities, particularly during the period in which this
report is being prepared;
(b)
Designed such internal control over financial reporting,
or caused such internal control over
financial reporting to be designed under our supervision,
to provide reasonable assurance regarding
the reliability of financial reporting and the preparation
of financial statements for external
purposes in accordance with generally accepted
accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in
this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of
the end of the period covered by this report based
on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control
over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter
in
the case of an annual report) that has materially
affected, or is reasonably likely to materially
affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of
internal control over financial reporting, to the
registrant’s auditors and the audit committee of the
registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses
in the design or operation of internal control
over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to
record, process, summarize and report financial
information; and
(b)
Any fraud, whether or not material, that
involves management or other employees who
have a
significant role in the registrant’s internal control over financial reporting.
February 18, 2020
/s/ Ryan M. Lance
Ryan M. Lance
Chairman and
Chief Executive Officer
EX-31.2
Exhibit 31.2
CERTIFICATION
I, Don E. Wallette, Jr.,
certify that:
1.
I have reviewed this annual report on Form
10-K
of ConocoPhillips;
2.
Based on my knowledge, this report does not contain
any untrue statement of a material fact or omit
to
state a material fact necessary to make the statements
made, in light of the circumstances under
which
such statements were made, not misleading with
respect to the period covered by this
report;
3.
Based on my knowledge, the financial statements,
and other financial information included in this
report,
fairly present in all material respects the financial
condition, results of operations and cash
flows of the
registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing
and maintaining disclosure
controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the registrant
and
have:
(a)
Designed such disclosure controls and procedures,
or caused such disclosure controls
and
procedures to be designed under our supervision,
to ensure that material information relating
to the
registrant, including its consolidated subsidiaries,
is made known to us by others within those
entities, particularly during the period in which this
report is being prepared;
(b)
Designed such internal control over financial reporting,
or caused such internal control over
financial reporting to be designed under our supervision,
to provide reasonable assurance regarding
the reliability of financial reporting and the preparation
of financial statements for external
purposes in accordance with generally accepted
accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in
this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of
the end of the period covered by this report based
on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control
over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter
in
the case of an annual report) that has materially
affected, or is reasonably likely to materially
affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most
recent evaluation of
internal control over financial reporting, to the
registrant’s auditors and the audit committee of the
registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses
in the design or operation of internal control
over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to
record, process, summarize and report financial
information; and
(b)
Any fraud, whether or not material, that
involves management or other employees who
have a
significant role in the registrant’s internal control over financial reporting.
February 18, 2020
/s/ Don E. Wallette, Jr.
Don E. Wallette, Jr.
Executive Vice President and
Chief Financial Officer
EX-32
Exhibit 32
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the Annual Report of ConocoPhillips
(the Company) on Form 10-K for the period ended
December 31, 2019, as filed with the U.S.
Securities and Exchange Commission on the
date hereof (the
Report), each of the undersigned hereby certifies,
pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002,
that to their knowledge:
(1)
The Report fully complies with the requirements
of Sections 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
(2)
The information contained in the Report fairly
presents, in all material respects, the financial
condition and results of operations of the Company.
February 18, 2020
/s/ Ryan M. Lance
Ryan M. Lance
Chairman and
Chief Executive Officer
/s/ Don E. Wallette, Jr.
Don E. Wallette, Jr.
Executive Vice President and
Chief Financial Officer
EX-99
Exhibit 99
DeGolyer
and
MacNaughton
5001
Spring
Valley
Road
Suite
800
Eas
t
Dallas,
Texas
75244
February 18, 2020
ConocoPhillips
925 N. Eldridge Parkway
Houston, Texas 77079
Re: SEC Process Review
Ladies and Gentlemen:
Pursuant to
your request,
DeGolyer and
MacNaughton has
performed a
process review
of the
processes
and
controls
used
within
ConocoPhillips
in
preparing
its
internal
estimates
of
proved
reserves,
as of
December
31, 2019.
This
process review,
which is
contemplated by
Item
1202 (a)(8)
of
Regulation S–K
of the
United States
Securities and
Exchange Commission
(SEC), has
been performed
specifically to address the adequacy and
effectiveness of ConocoPhillips’ internal processes
and controls
relative to its
estimation of proved
reserves in compliance
with Rules 4–10(a)
(1)–(32) of Regulation
S–
X of the SEC.
DeGolyer
and
MacNaughton
has
participated
as
an
independent
member
of
the
internal
ConocoPhillips
Reserves
Compliance
Assessment
Team
in
reviews
and
discussions
with
each
of
the
relevant
ConocoPhillips
business
units
relative
to
SEC
proved
reserves
estimation.
DeGolyer
and
MacNaughton has participated in the
review of all major fields
in all countries in
which ConocoPhillips
has
proved
reserves
worldwide,
which
ConocoPhillips
has
indicated
represents
over
90
percent
of
its
estimated total proved reserves as of December 31, 2019.
The
reviews
with
ConocoPhillips’
technical staff
involved
presentations
and
discussions
of
a)
basic reservoir data, including
seismic data, well-log data,
pressure and production tests,
core analysis,
pressure-volume-temperature
data,
and
production
history,
b)
technical
methods
employed
in
SEC
proved
reserves
estimation,
including
performance
analysis,
geology,
mapping,
and
volumetric
estimates,
c)
economic
analysis,
and
d)
commercial
assessment,
including
the
legal
basis
for
the
interest in the reserves, primarily related
to lease agreements and other petroleum license
agreements,
such as concession and production sharing agreements.
ConocoPhillips
February 18, 2020
Page 2 of 2
A field examination of the properties was not considered necessary for the purposes of this
review of ConocoPhillips’ processes and controls.
It
is
DeGolyer
and
MacNaughton’s
opinion
that
ConocoPhillips’
estimates
of
proved reserves
for the
properties
reviewed were
prepared by
the use
of recognized
geologic and
engineering methods
generally
accepted
by
the
petroleum
industry.
The
method
or
combination
of
methods
used
in
the
analysis of
each reservoir was
tempered by
ConocoPhillips’ experience with
similar reservoirs,
stage of
development,
quality
and
completeness
of
basic
data,
and
production
history.
It
is
DeGolyer
and
MacNaughton’s
opinion
that
the
general
processes
and
controls
employed
by
ConocoPhillips
in
estimating its
December 31,
2019, proved
reserves for
the properties
reviewed are
in accordance
with
the SEC reserves definitions.
This
process
review
of
ConocoPhillips’
procedures
and
methods
does
not
constitute
a
review,
study, or independent
audit of ConocoPhillips’
estimated proved reserves
and corresponding future
net
revenues. This
process review
is not
intended to
indicate that
DeGolyer and
MacNaughton is
offering
any opinion as to the reasonableness of the reserves estimates reported by ConocoPhillips.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has
been providing
petroleum consulting
services throughout
the world
since 1936.
Neither DeGolyer
and
MacNaughton nor
any employee
who participated
in this
project has
any financial
interest, including
stock
ownership,
in
ConocoPhillips.
DeGolyer
and
MacNaughton’s
fees
were
not
contingent
on
the
results of its evaluation.
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
/s/ Charles F. Boyette
Charles F. Boyette,
P.E.
President
DeGolyer and MacNaughton