false 2019 --12-31 0.01 P10Y 5 23 17 - - 6 730 FALSE 0001163165 FY 998 1 P30D 283 37.5 56.9 No No <div>Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.</div> <div>*Primarily euro and Norwegian krone.</div> <div>*We paid interest to, or received interest from, various affiliates. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.</div> <div>(1)Sales and other operating revenues are attributable to countries based on the location of the selling operation.</div> <div>(4)Long-lived assets do not include $1,236 million of net PP&E associated with assets held for sale as of December 31, 2019. See Note 5—Acquisitions and Dispositions, for additional information.</div> <div>(2)Defined as net PP&E plus equity investments and advances to affiliated companies.</div> <div>(3)Long-lived assets do not include $426 million of net PP&E associated with assets held for sale as of December 31, 2019. 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2019
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form
10-K
 
 
(Mark One)
 
[
X
]
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF
 
1934
 
For the fiscal year ended
 
December 31, 2019
 
 
OR
 
 
[
 
]
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
 
OF THE SECURITIES EXCHANGE ACT OF
 
1934
 
For the transition period from
 
to
 
 
Commission file number:
001-32395
 
ConocoPhillips
 
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
01-0562944
 
(State or other jurisdiction of
 
(I.R.S. Employer
 
incorporation or organization)
 
Identification No.)
 
925 N. Eldridge Parkway
Houston
,
TX
 
77079
 
(Address of principal executive offices)
 
(Zip Code)
 
 
Registrant's telephone number, including area code:
281
-
293-1000
 
Securities registered pursuant to Section 12(b) of the
 
Act:
Title of each class
Trading symbols
Name of each exchange on which registered
 
Common Stock, $.01 Par Value
COP
New York Stock Exchange
 
7% Debentures due 2029
CUSIP—718507BK1
New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the
 
Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer,
 
as defined in Rule 405 of the Securities Act.
 
 
[x]
Yes
 
[ ] No
Indicate by check mark if the registrant is not required to file reports
 
pursuant to Section 13 or Section 15(d) of the
Act.
 
[ ] Yes
 
[x]
No
Indicate by check mark whether the registrant (1) has filed all reports required
 
to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
 
for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for
 
the past 90 days. [x]
Yes
 
[ ] No
Indicate by check mark whether the registrant has submitted electronically
 
every Interactive Data File required to be
submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
 
chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit such files).
 
[x]
Yes
 
[ ] No
 
Indicate by check mark whether the registrant is a large accelerated filer,
 
an accelerated filer, a non-accelerated filer,
 
a
smaller reporting company,
 
or an emerging growth company.
 
See the definitions of “large accelerated filer,”
“accelerated filer,” “smaller reporting
 
company” and “emerging growth company” in Rule 12b-2 of the Exchange
 
Act.
 
Large accelerated filer
[x]
 
Accelerated filer [
 
]
 
Non-accelerated filer [
 
]
 
Smaller reporting company
 
[
 
]
 
Emerging growth company
 
[
 
]
 
If an emerging growth company,
 
indicate by check mark if the registrant has elected not to use the extended
transition period for complying with any new or revised financial accounting
 
standards provided pursuant to Section
13(a) of the Exchange Act. [
 
]
 
Indicate by check mark whether the registrant is a shell company (as defined
 
in Rule 12b-2 of the Act). [
 
] Yes
 
[x]
No
The aggregate market value of common stock held by non-affiliates of
 
the registrant on June 28, 2019, the last
business day of the registrant’s most recently
 
completed second fiscal quarter, based on
 
the closing price on that date
of $61.00, was $
67.7
 
billion.
 
The registrant had
1,081,132,415
 
shares of common stock outstanding at January 31, 2020.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be
 
held on May 12, 2020 (Part III)
 
 
 
 
 
TABLE OF CONTENTS
 
 
 
Page
Commonly Used Abbreviations……………………………………………………………………….
1
Item
PART
 
I
1 and 2.
Business and Properties
 
......................................................................................................
 
2
Corporate Structure
 
........................................................................................................
 
2
Segment and Geographic Information
 
...........................................................................
 
2
Alaska
 
.......................................................................................................................
 
4
Lower 48
 
...................................................................................................................
 
6
Canada ......................................................................................................................
 
9
Europe and North Africa
 
...........................................................................................
 
10
Asia Pacific and Middle East
 
....................................................................................
 
12
Other International
 
....................................................................................................
 
17
Competition ...................................................................................................................
 
19
General
 
...........................................................................................................................
 
19
1A.
Risk Factors
 
........................................................................................................................
 
21
1B.
Unresolved Staff Comments
 
...............................................................................................
 
28
3.
Legal Proceedings
 
...............................................................................................................
 
28
4.
Mine Safety Disclosures
 
.....................................................................................................
 
28
Information About our Executive Officers
 
.........................................................................
 
29
PART
 
II
5.
Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
 
............................................................................
 
31
6.
Selected Financial Data ......................................................................................................
 
34
7.
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
 
.....................................................................................................
 
35
7A.
Quantitative and Qualitative Disclosures
 
About Market Risk
 
............................................
 
72
8.
Financial Statements and Supplementary
 
Data
 
...................................................................
 
75
9.
Changes in and Disagreements with Accountants
 
on Accounting and
Financial Disclosure
 
.......................................................................................................
 
185
9A.
Controls and Procedures
 
.....................................................................................................
 
185
9B.
Other Information
 
...............................................................................................................
 
185
PART
 
III
10.
Directors, Executive Officers and Corporate Governance
 
..................................................
 
186
11.
Executive Compensation
 
....................................................................................................
 
186
12.
Security Ownership of Certain Beneficial Owners
 
and Management and
 
Related Stockholder Matters
 
..........................................................................................
 
186
13.
Certain Relationships and Related Transactions, and Director
 
Independence....................
 
186
14.
Principal Accounting Fees and Services
 
.............................................................................
 
186
PART
 
IV
15.
Exhibits, Financial Statement Schedules
 
............................................................................
 
187
Signatures ...........................................................................................................................
 
197
 
1
Commonly Used Abbreviations
 
The following industry-specific, accounting and
 
other terms, and abbreviations may be commonly
 
used in this
report.
 
Currencies
Accounting
$ or USD
U.S. dollar
ARO
asset retirement obligation
CAD
Canadian dollar
ASC
accounting standards codification
GBP
British pound
ASU
accounting standards update
DD&A
depreciation, depletion and
Units of Measurement
amortization
BBL
barrel
FASB
Financial Accounting Standards
BCF
billion cubic feet
Board
BOE
barrels of oil equivalent
FIFO
first-in, first-out
MBD
thousands of barrels per day
G&A
general and administrative
MCF
thousand cubic feet
GAAP
generally accepted accounting
 
MMBOE
million barrels of oil equivalent
principles
MBOED
thousands of barrels of oil
 
LIFO
last-in, first-out
equivalent per day
NPNS
normal purchase normal sale
MMBTU
million British thermal units
PP&E
properties, plants and equipment
MMCFD
million cubic feet per day
SAB
staff accounting bulletin
VIE
variable interest entity
Industry
CBM
coalbed methane
Miscellaneous
E&P
exploration and production
EPA
Environmental Protection Agency
FEED
front-end engineering and design
EU
European Union
FPS
floating production system
FERC
Federal Energy Regulatory
 
FPSO
floating production, storage and
Commission
offloading
GHG
greenhouse gas
JOA
joint operating agreement
HSE
health, safety and environment
LNG
liquefied natural gas
ICC
International Chamber of
 
NGLs
natural gas liquids
Commerce
OPEC
Organization of Petroleum
 
ICSID
World Bank’s
 
International
 
Exporting Countries
Centre for Settlement of
PSC
production sharing contract
Investment Disputes
PUDs
proved undeveloped reserves
IRS
Internal Revenue Service
SAGD
steam-assisted gravity drainage
OTC
over-the-counter
WCS
Western Canada Select
NYSE
New York Stock Exchange
WTI
West Texas
 
Intermediate
SEC
U.S. Securities and Exchange
Commission
TSR
total shareholder return
U.K.
United Kingdom
U.S.
United States of America
 
 
2
PART
 
I
 
 
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this
 
report to
refer to the businesses of ConocoPhillips and its
 
consolidated subsidiaries.
 
Items 1 and 2—Business and
Properties, contain forward-looking statements
 
including, without limitation, statements
 
relating to our plans,
strategies, objectives, expectations and intentions
 
that are made pursuant to the “safe harbor”
 
provisions of the
Private Securities Litigation Reform Act of 1995.
 
The words “anticipate,” “estimate,” “believe,”
 
“budget,”
“continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,”
 
“will,” “would,”
“expect,” “objective,” “projection,” “forecast,” “goal,”
 
“guidance,” “outlook,” “effort,” “target” and similar
expressions identify forward-looking statements.
 
The company does not undertake to update, revise
 
or correct
any forward-looking information unless required to
 
do so under the federal securities laws.
 
Readers are
cautioned that such forward-looking statements should
 
be read in conjunction with the company’s disclosures
under the headings “Risk Factors” beginning on page
 
21 and “CAUTIONARY STATEMENT
 
FOR THE
PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS
 
OF THE PRIVATE
 
SECURITIES LITIGATION
REFORM ACT OF 1995,” beginning on page
 
 
 
Items 1 and 2.
 
BUSINESS AND PROPERTIES
 
 
CORPORATE STRUCTURE
 
ConocoPhillips is an independent E&P company
 
with operations and activities in 17 countries.
 
Our diverse,
low cost of supply portfolio includes resource-rich
 
unconventional plays in North America;
 
conventional
assets in North America, Europe, Asia and Australia;
 
LNG developments; oil sands assets in Canada;
 
and an
inventory of global conventional and unconventional
 
exploration prospects.
 
Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately
 
10,400 people worldwide and had total assets
 
of
 
$71
billion.
 
 
ConocoPhillips was incorporated in the state
 
of Delaware on November 16, 2001, in connection
 
with, and in
anticipation of, the merger between Conoco Inc. and Phillips
 
Petroleum Company.
 
The merger between
Conoco and Phillips was consummated on
 
August 30, 2002.
 
 
 
SEGMENT AND GEOGRAPHIC INFORMATION
 
For operating segment and geographic information,
 
see Note 25—Segment Disclosures and Related
Information, in the Notes to Consolidated Financial
 
Statements, which is incorporated herein by reference.
 
 
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on
 
a worldwide
basis.
 
At December 31, 2019, our operations were
 
producing in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, Malaysia, Libya, China and
 
Qatar.
 
 
The information listed below appears in the “Oil
 
and Gas Operations” disclosures following the
 
Notes to
Consolidated Financial Statements and is incorporated
 
herein by reference:
 
 
Proved worldwide crude oil, NGLs, natural gas
 
and bitumen reserves.
 
Net production of crude oil, NGLs, natural gas
 
and bitumen.
 
Average sales prices of crude oil, NGLs, natural gas and bitumen.
 
Average production costs per BOE.
 
Net wells completed, wells in progress and productive
 
wells.
 
Developed and undeveloped acreage.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3
The following table is a summary of the proved
 
reserves information included in the “Oil
 
and Gas Operations”
disclosures following the Notes to Consolidated
 
Financial Statements.
 
Approximately 80 percent of our
proved reserves are located in politically
 
stable countries that belong to the Organization for Economic
Cooperation and Development.
 
Natural gas reserves are converted to BOE based
 
on a 6:1 ratio: six MCF of
natural gas converts to one BOE.
 
See Management’s Discussion and Analysis of Financial Condition and
Results of Operations for a discussion of factors
 
that will enhance the understanding of the following
 
summary
reserves table.
 
 
Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31
2019
2018
2017
Crude oil
Consolidated operations
2,562
2,533
2,322
Equity affiliates
73
78
83
Total Crude Oil
2,635
2,611
2,405
Natural gas liquids
Consolidated operations
361
349
354
Equity affiliates
39
42
45
Total Natural Gas Liquids
400
391
399
Natural gas
Consolidated operations
1,209
1,265
1,267
Equity affiliates
736
760
717
Total Natural Gas
1,945
2,025
1,984
Bitumen
Consolidated operations
282
236
250
Total Bitumen
282
236
250
Total consolidated operations
4,414
4,383
4,193
Total equity affiliates
848
880
845
Total company
5,262
5,263
5,038
 
 
Total production of 1,348 MBOED increased 5 percent in 2019 compared with 2018.
 
 
The increase in total
average production primarily resulted from new wells
 
online in the Lower 48; an increased interest in
 
the
Western North Slope (WNS) and Greater Kuparuk Area (GKA) of Alaska following
 
acquisitions closed in
2018; and higher production in Norway due to drilling
 
activity and the startup of Aasta Hansteen
 
in December
2018.
 
The increase in production was partly offset by normal
 
field decline and disposition impacts,
 
primarily
from the U.K. asset sale in 2019 and non-core
 
asset sales in the Lower 48 during 2018.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4
Production excluding Libya was 1,305 MBOED in
 
2019 compared with 1,242 MBOED in 2018, an
 
increase of
63 MBOED or 5 percent.
 
Underlying production, which excludes Libya and
 
the net volume impact from
closed dispositions and acquisitions of 51 MBOED
 
in 2019 and 47 MBOED in 2018, is used to measure
 
our
ability to grow production organically.
 
Our underlying production grew 5 percent to
 
1,254 MBOED in 2019
from 1,195 MBOED in 2018.
 
Our worldwide annual average realized price
 
was $48.78 per BOE in 2019,
 
a decrease of 9 percent compared
with $53.88 per BOE in 2018,
 
reflecting weaker marker prices as a result of
 
macroeconomic demand concerns.
 
Our worldwide annual average crude oil price
 
decreased 10 percent, from $68.13 per barrel
 
in 2018 to $60.99
per barrel in 2019.
 
Additionally, our worldwide annual average NGL prices decreased 34 percent,
 
from
$30.48 per barrel in 2018 to $20.09 per barrel in
 
2019.
 
Our worldwide annual average natural gas price
decreased 11 percent, from $5.65 per MCF in 2018 to $5.03 per MCF
 
in 2019.
 
Average annual bitumen prices
increased 42 percent, from $22.29 per barrel in 2018
 
to $31.72 per barrel in 2019.
 
 
ALASKA
 
The Alaska segment primarily explores for, produces, transports
 
and markets crude oil, natural gas and NGLs.
 
We are the largest crude oil producer in Alaska and have major ownership interests in
 
two of North America’s
largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk.
 
We also have a 100 percent
interest in the Alpine Field, located on the Western North Slope.
 
Additionally, we are one of Alaska’s largest
owners of state, federal and fee exploration leases,
 
with approximately 1.32 million net undeveloped
 
acres at
year-end 2019.
 
Alaska operations contributed 25 percent
 
of our worldwide liquids production and less
 
than 1
percent of our natural gas production.
 
 
2019
Interest
Operator
Liquids
MBD
Natural Gas
MMCFD
Total
MBOED
Average Daily Net Production
Greater Prudhoe Area
36.1
%
BP
81
4
81
Greater Kuparuk Area
91.4-94.7
ConocoPhillips
86
2
86
Western North Slope
100.0
ConocoPhillips
50
1
51
Total Alaska
217
7
218
 
 
Greater Prudhoe Area
The Greater Prudhoe Area includes the Prudhoe
 
Bay Field and five satellite fields, as well as the
 
Greater Point
McIntyre Area fields.
 
Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large
waterflood and enhanced oil recovery operation,
 
as well as a gas plant which processes
 
natural gas to recover
NGLs before reinjection into the reservoir.
 
Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight
Sun and Orion, while the Point McIntyre,
 
Niakuk, Raven, Lisburne and North Prudhoe Bay
 
State fields are
part of the Greater Point McIntyre Area.
 
 
Greater Kuparuk Area
We operate the Greater Kuparuk Area, which consists of the Kuparuk Field and four
 
satellite fields: Tarn,
Tabasco, Meltwater and West Sak.
 
Kuparuk is located 40 miles west of Prudhoe
 
Bay.
 
Field installations
include three central production facilities
 
which separate oil, natural gas and water, as well as a separate
seawater treatment plant.
 
Development drilling at Kuparuk consists of
 
rotary-drilled wells and horizontal
multi-laterals from existing well bores utilizing
 
coiled-tubing drilling.
 
 
 
 
 
 
5
 
Western North Slope
On the Western North Slope, we operate the Colville River Unit, which includes the
 
Alpine Field and three
satellite fields: Nanuq, Fiord and Qannik.
 
Alpine is located 34 miles west of Kuparuk.
 
In 2015, first oil was
achieved at Alpine West CD5,
 
a drill site which extends the Alpine reservoir west
 
into the National Petroleum
Reserve-Alaska (NPR-A).
 
In 2019, we continued drilling additional
 
wells using the available well slots on this
pad.
 
 
The Greater Mooses Tooth Unit, the first unit established entirely within the
 
NPR-A, was formed in 2008.
 
In
2017, we began construction in the unit with two
 
drill sites; Greater Mooses Tooth #1 (GMT-1) and Greater
Mooses Tooth #2 (GMT-2).
 
GMT-1 achieved first oil in the fourth quarter of 2018 and completed drilling in
2019.
 
We expect first oil from GMT-2 in 2021.
 
 
Alaska North Slope Gas
In 2016, we, along with affiliates of Exxon Mobil Corporation,
 
BP p.l.c. and Alaska Gasline Development
Corporation (AGDC), a state-owned corporation,
 
completed preliminary FEED technical
 
work for a potential
LNG project which would liquefy and export natural
 
gas from Alaska’s North Slope and deliver it to
market.
 
In 2016, we, along with the affiliates of ExxonMobil
 
and BP,
 
indicated our intention not to progress
into the next phase of the project due to changes in
 
the economic environment.
 
AGDC decided to continue on
its own.
 
In 2019, affiliates of ExxonMobil and BP agreed
 
to each contribute up to $5 million or approximately
one third of AGDC’s anticipated costs for full-year 2020.
 
In 2020, AGDC will be focused on permitting
efforts, the most important of which is the National Environmental
 
Protection Act process before the FERC.
 
FERC’s final milestones are the Publication of Notice of Availability of Final Environmental Impact
Statement, which is scheduled for March 6, 2020,
 
and the Issuance of Final Order, which is scheduled for June
4, 2020.
 
AGDC has recently contracted with Fluor
 
Corporation to evaluate cost reduction opportunities
 
in
preparation for soliciting partners for the project.
 
We continue to be willing to sell our North Slope gas to the
project but do not plan to take an equity position.
 
 
Exploration
Appraisal of the Willow Discovery, located in the northeast portion of the NPR-A, continued
 
throughout 2019
with five appraisal wells.
 
In 2020, we will continue appraisal of
 
the Willow Discovery and explore the
Harpoon Prospect, located southwest of Willow.
 
In 2019, we drilled the West Willow-2 well to appraise the 2018 West Willow oil discovery.
 
 
In late 2018, we commenced appraisal of the Putu
 
Discovery with a long reach well from
 
existing Alpine CD4
infrastructure.
 
The CD4 appraisal well finished drilling
 
and flow tested in 2019.
 
A supporting injector well
was drilled in late 2019 for a 2020 injectivity test.
 
The Cairn 2S-315 Well was drilled in late 2018 from the 2S drill site on state leases
 
in the Kuparuk River Unit.
 
A long-term flow test was commenced in 2019 and
 
evaluations are ongoing.
 
 
A 3-D
 
seismic survey was completed in 2018 over
 
a 250-mile area on state lands.
 
We are currently evaluating
this seismic data for future exploration opportunities.
 
We were successful in the federal lease sale on the North Slope in the fourth quarter
 
of 2019, where we were
the high bidder on three tracts for a total of
 
approximately 33,000 net acres.
 
 
Acquisitions
In the third quarter of 2019, we completed the
 
Nuna discovery acreage acquisition, expanding
 
the Kuparuk
River Unit by 21,000 acres and leveraging legacy
 
infrastructure.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
6
 
Transportation
We transport the petroleum liquids produced on the North Slope to south central
 
Alaska through an 800-mile
pipeline that is part of Trans-Alaska Pipeline System (TAPS).
 
We have a 29.1
 
percent ownership interest in
TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines
 
on the North Slope.
 
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope
production, using five company-owned, double-hulled
 
tankers,
 
and charters third-party vessels as necessary.
 
The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.
 
 
LOWER 48
 
The Lower 48 segment consists of operations located
 
in the contiguous U.S. and the Gulf of Mexico.
 
Organized into the Gulf Coast and Great Plains business
 
units, we hold 10.4
 
million net onshore and offshore
acres, with a portfolio of conventional production from
 
legacy assets as well as newer production from
 
our low
cost of supply, shorter cycle time, resource-rich unconventional plays.
 
Based on 2019 production volumes, the
Lower 48 is the company’s largest segment and contributed 39 percent of our
 
worldwide liquids production
and 22 percent of our natural gas production.
 
 
2019
Interest
Operator
Liquids
MBD
Natural Gas
MMCFD
Total
MBOED
Average Daily Net Production
Eagle Ford
Various
%
Various
174
251
216
Gulf of Mexico
Various
Various
15
11
16
Gulf Coast—Other
Various
Various
3
9
5
 
Total Gulf Coast
192
271
237
Bakken
Various
Various
82
92
97
Permian Unconventional
Various
Various
40
94
56
Permian Conventional
Various
Various
20
59
30
Anadarko Basin
Various
Various
5
58
14
Wyoming/Uinta
Various
Various
-
36
6
Niobrara*
Various
Various
8
12
11
 
Total Great Plains
155
351
214
Total Lower 48
347
622
451
*Classified as held-for-sale as of December 31, 2019.
 
See 'Dispositions' below for additional information.
 
 
Onshore
We hold 10.3
 
million net acres of onshore conventional
 
and unconventional acreage in the Lower
 
48, the
majority of which is either held by production or
 
owned by the company.
 
Our unconventional holdings total
approximately 1.7 million net acres in the following
 
areas:
 
 
 
610,000 net acres in the Bakken, located in
 
North Dakota and eastern Montana.
 
 
234,000 net acres in Central Louisiana, where
 
we recently announced our intention to
 
discontinue
exploration activities.
 
201,000 net acres in the Eagle Ford, located in South
 
Texas.
 
 
167,000 net acres in the Permian, located in West Texas and southeastern New Mexico.
 
98,000 net acres in the Niobrara, located in northeastern
 
Colorado.
 
 
363,000 net acres in other areas with unconventional
 
potential.
 
 
 
 
7
 
The majority of our 2019 onshore production
 
originated from the Big 3—Eagle Ford,
 
Bakken and Permian
Unconventional.
 
Onshore activities in 2019 were centered mostly
 
on continued development of assets, with an
emphasis on areas with low cost of supply, particularly in growing unconventional
 
plays.
 
Our major focus
areas in 2019 included the following:
 
 
 
Eagle Ford—The Eagle Ford continued full-field
 
development in 2019.
 
We operated seven rigs on
average in 2019, resulting in 155 operated wells
 
drilled and 166 operated wells brought online.
 
Production increased 16 percent in 2019 compared
 
with 2018, averaging 216 MBOED and 186
MBOED, respectively.
 
 
Bakken—We operated an average of three rigs during the year in the Bakken and participated
 
in
additional development activities operated by co-venturers.
 
We continued our pad drilling with 62
operated wells drilled during the year and 44
 
operated wells brought online.
 
Production increased 15
percent in 2019
 
compared with 2018, averaging 97 MBOED
 
and 84 MBOED, respectively.
 
 
Permian Basin—The Permian Basin is a combination
 
of legacy conventional and unconventional
assets.
 
We operated an average of three rigs during the year in the Permian Basin, resulting
 
in 29
operated wells drilled and 35 operated wells brought
 
online.
 
The Permian Basin produced 86
MBOED in 2019, increasing 30 percent compared
 
with 2018, including 56 MBOED of
unconventional production.
 
Gulf of Mexico
At year-end 2019, our portfolio of producing properties
 
in the Gulf of Mexico totaled approximately 60,000
net acres.
 
A majority of the production consists
 
of three fields operated by co-venturers:
 
 
15.9 percent nonoperated working interest in
 
the unitized Ursa Field located in the Mississippi
 
Canyon
Area.
 
15.9 percent nonoperated working interest in
 
the Princess Field, a northern subsalt extension
 
of the
Ursa Field.
 
12.4 percent nonoperated working interest in
 
the unitized K2 Field, comprised of seven blocks
 
in the
Green Canyon Area.
 
Dispositions
We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass
Pipeline near Sabine Pass, Texas, intended to provide us with terminal and pipeline
 
capacity for the receipt,
storage and regasification of LNG purchased from
 
Qatar Liquefied Gas Company Limited (3) (QG3).
 
We
previously held a 12.4 percent interest in
 
Golden Pass LNG Terminal and Golden Pass Pipeline, but we sold
those interests in the second quarter of 2019 while
 
retaining the basic use agreements.
 
In the fourth quarter of 2019, we completed the sale
 
of our interests
 
in the Magnolia Field in the Gulf of
Mexico.
 
Production from this disposed asset
 
was less than one MBOED in 2019.
 
In the fourth quarter of 2019, we entered into an
 
agreement to sell our interests in the Niobrara,
 
with an
anticipated closing date in the first quarter
 
of 2020.
 
Production from the interests to be disposed
 
was
approximately 11 MBOED in 2019.
 
In January 2020, we entered into an agreement to
 
sell our interests in certain non-core properties
 
for $186
million, plus customary adjustments.
 
The assets met the held for sale criteria in January
 
2020 and the
transaction is expected to be completed in the
 
first quarter of 2020.
 
This disposition will not have a significant
impact on Lower 48 production.
 
 
For additional information on these transactions,
 
see Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
 
 
8
 
Exploration
 
Our exploration focus is on onshore unconventional
 
plays, which in 2019 included the Delaware
 
in the
Permian Basin, and the Eagle Ford in south Texas.
 
In the third quarter of 2019, we announced our
 
decision to
discontinue exploration activities in the Central
 
Louisiana Austin Chalk.
 
Facilities
 
 
Lost Cabin Gas Plant—We operate and own a 46 percent interest in the Lost Cabin
 
Gas Plant, a 246
MMCFD capacity natural gas processing facility
 
in Lysite, Wyoming.
 
The plant is currently operating at
less than capacity due to a fire in December 2018.
 
Restoration efforts are ongoing and anticipated to be
completed in the second half of 2020.
 
The expected production loss in 2020 is
 
immaterial to the segment.
 
Helena Condensate Processing Facility—We operate and own the Helena Condensate
 
Processing Facility,
a 110 MBD condensate processing plant located in Kenedy, Texas.
 
 
Sugarloaf Condensate Processing Facility—We operate and own an 87.5 percent interest
 
in the Sugarloaf
Condensate Processing Facility, a 30 MBD condensate processing plant located
 
near Pawnee,
 
Texas.
 
Bordovsky Condensate Processing Facility—We operate and own the Bordovsky Condensate
 
Processing
Facility, a 15 MBD condensate processing plant located in Kenedy, Texas.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
CANADA
 
Our Canadian operations mainly consist of the
 
Surmont oil sands development in Alberta
 
and the liquids-rich
Montney unconventional play in British Columbia.
 
In 2019, operations in Canada contributed
 
7 percent of our
worldwide liquids production and less than 1 percent
 
of our natural gas production.
 
2019
Natural
Liquids
Gas
Bitumen
Total
Interest
Operator
MBD
MMCFD
MBD
MBOED
Average Daily Net Production
Surmont
50.0
%
ConocoPhillips
-
-
60
60
Montney
100.0
ConocoPhillips
1
9
-
3
Total Canada
1
9
60
63
 
 
Surmont
Our bitumen resources in Canada are produced
 
via an enhanced thermal oil recovery method
 
called SAGD,
whereby steam is injected into the reservoir, effectively liquefying the heavy
 
bitumen, which is recovered and
pumped to the surface for further processing.
 
We hold approximately 0.6 million net acres of land in the
Athabasca Region of northeastern Alberta.
 
The Surmont oil sands leases are located approximately
 
35 miles south of Fort McMurray, Alberta.
 
Surmont
is a 50/50 joint venture with Total S.A.
 
The second phase of the Surmont Project achieved
 
first production in
2015 and reached peak production in 2018.
 
We are focused on structurally lowering costs, reducing GHG
intensity and optimizing asset performance.
 
 
The Alberta government imposed a production
 
curtailment impacting the industry beginning
 
in January 2019.
 
The curtailment measure,
 
which impacted our annualized average production
 
by 3 MBOED in 2019, is
intended to strengthen the WCS differential to WTI at
 
Hardisty.
 
The curtailment program is established and
administered by the Alberta Energy Regulator under the
Curtailment Rules
 
regulation, which is currently set to
expire on December 31, 2020.
 
Montney
We hold approximately 151,000 net acres in the emerging unconventional Montney play
 
in northeast British
Columbia.
 
Our Montney activity in 2019 included drilling
 
16 horizontal wells, completing 14 horizontal
 
wells
and acquiring approximately 6,000 additional net
 
acres.
 
Production from our 2019 drilling program
commenced in February 2020 following the completion
 
of third-party offtake facilities.
 
Appraisal drilling and completions activity
 
will continue in 2020 to further explore the area’s resource
potential.
 
Exploration
 
Our primary exploration focus is assessing our
 
Montney onshore unconventional acreage
 
in Western Canada.
 
Additionally, we have exploration acreage in the Mackenzie Delta/Beaufort
 
Sea Region and the Arctic Islands.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10
EUROPE AND NORTH AFRICA
 
The Europe and North Africa segment consisted
 
of operations in Norway, Libya and the U.K. and exploration
activities in Norway and Libya.
 
In 2019, operations in Europe and North Africa contributed
 
16 percent of our
worldwide liquids production and 17 percent of natural
 
gas production.
 
 
Norway
2019
Liquids
Natural Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Ekofisk Area
35.1
%
ConocoPhillips
50
44
57
Heidrun
24.0
Equinor
14
29
19
Alvheim
20.0
Aker BP
10
12
12
Visund
9.1
Equinor
4
46
12
Aasta Hansteen
10.0
Equinor
-
64
11
Troll
1.6
Equinor
2
49
10
Other
Various
Equinor
8
10
10
Total Norway
88
254
131
 
 
The Greater Ekofisk Area is located approximately
 
200 miles offshore Stavanger, Norway, in the North Sea,
and comprises three producing fields: Ekofisk,
 
Eldfisk and Embla.
 
Crude oil is exported to Teesside, England,
and the natural gas is exported to Emden,
 
Germany.
 
The Ekofisk and Eldfisk fields consist
 
of several
production platforms and facilities, including
 
the Ekofisk South and Eldfisk II developments.
 
Continued
development drilling in the Greater Ekofisk
 
Area is expected to contribute additional production
 
over the
coming years, as additional wells come online.
 
The Heidrun Field is located in the Norwegian
 
Sea.
 
Produced crude oil is stored in a floating
 
storage unit and
exported via shuttle tankers.
 
Part of the natural gas is currently injected into
 
the reservoir for optimization of
crude oil production,
 
some gas is transported for use as feedstock in
 
a methanol plant in Norway, in which we
own an 18 percent interest,
 
and the remainder is transported to Europe via
 
gas processing terminals in Norway.
 
The Alvheim Field is located in the northern part of
 
the North Sea near the border with the
 
U.K. sector, and
consists of a FPSO vessel and subsea installations.
 
Produced crude oil is exported via shuttle
 
tankers, and
natural gas is transported to the Scottish Area
 
Gas Evacuation (SAGE) Terminal at St. Fergus, Scotland,
through the SAGE Pipeline.
 
Visund is an oil and gas field located in the North Sea and consists of a floating
 
drilling, production and
processing unit, and subsea installations.
 
Crude oil is transported by pipeline to a nearby
 
third-party field for
storage and export via tankers.
 
The natural gas is transported to a gas processing
 
plant at Kollsnes, Norway,
through the Gassled transportation system.
 
Aasta Hansteen is located in the Norwegian
 
Sea and achieved first production in December
 
2018.
 
Produced
condensate is loaded onto shuttle tankers
 
and transported to market.
 
Gas is transported through the Polarled
gas pipeline to the onshore Nyhamna processing
 
plant for final processing prior to export
 
to market.
 
The Troll Field lies in the northern part of the North Sea and consists
 
of the Troll A, B and C platforms.
 
The
natural gas from Troll A is transported to Kollsnes, Norway.
 
Crude oil from floating platforms Troll B and
Troll C is transported to Mongstad, Norway, for storage and export.
 
We also have varying ownership interests in two other producing fields in the Norway
 
sector of the North Sea.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11
Exploration
 
In 2019, we operated the Busta and Enniberg exploration
 
wells in Block 25/7 in the North Sea.
 
The Busta well
encountered hydrocarbons and will be evaluated
 
for future appraisal consideration.
 
The Enniberg well
encountered insufficient hydrocarbons and was expensed
 
as a dry hole in 2019.
 
We also participated in the
Canela exploration well in the Heidrun area of the
 
Norwegian Sea.
 
The well encountered hydrocarbons and
will be further evaluated to determine commerciality.
 
In 2019, we were awarded two new exploration
licenses; PL1001 and PL1009; and one acreage
 
addition, PL782SD.
 
Transportation
We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline
 
which carries crude oil
from Ekofisk to a crude oil stabilization
 
and NGLs processing facility in Teesside, England.
 
United Kingdom
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Britannia Satellites*
26.3–93.8
%
ConocoPhillips
7
55
16
J-Area
32.5–36.5
ConocoPhillips
6
38
12
Britannia
58.7
ConocoPhillips
2
49
10
East Irish Sea
100.0
Spirit Energy
-
48
8
Clair
7.5
BP
4
1
4
Other
Various
Various
-
2
-
Total United Kingdom
19
193
50
*Includes the Chevron-operated Alder Field, ConocoPhillips equity interest was 26.3 percent.
 
 
On September 30, 2019, we completed the sale of
 
two ConocoPhillips U.K. subsidiaries
 
to Chrysaor E&P
Limited, including all of our producing assets
 
in the U.K.
 
Annualized average production from the assets
 
sold
was 50 MBOED in 2019.
 
For additional information on this transaction,
 
see Note 5—Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial
 
Statements.
 
 
We retained our Teesside,
 
England oil terminal, where we are the operator
 
and have a 40.25 percent ownership
interest, to support our Norway operations.
 
 
Libya
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Waha Concession
16.3
%
Waha Oil Co.
38
31
43
Total Libya
38
31
43
 
 
The Waha Concession consists of multiple concessions and encompasses nearly
 
13 million gross acres in the
Sirte Basin.
 
Our production operations in Libya and related
 
oil exports have periodically been interrupted
 
over
the last several years due to the shutdown of the
 
Es Sider crude oil export terminal.
 
In 2019, we had 19 crude
liftings from Es Sider.
 
The number of crude liftings from the Es Sider
 
crude oil export terminal in 2020 is
uncertain due to civil unrest.
 
In January 2020, we declared Force Majeure to
 
our crude shippers following the
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12
blockade of the Es Sider crude oil export terminal
 
and the declaration of Force Majeure by the
 
National Oil
Corporation of Libya.
 
 
ASIA PACIFIC AND MIDDLE EAST
 
The Asia Pacific and Middle East segment has
 
exploration and production operations
 
in China, Indonesia,
Malaysia and Australia and producing operations
 
in Qatar and Timor-Leste.
 
In 2019, operations in the Asia
Pacific and Middle East segment contributed 13
 
percent of our worldwide liquids production
 
and 60 percent of
natural gas production.
 
 
Australia and Timor-Leste
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
ConocoPhillips/
Australia Pacific LNG
37.5
%
Origin Energy
-
679
113
Bayu-Undan*
56.9
ConocoPhillips
10
194
43
Athena/Perseus*
50.0
ExxonMobil
-
31
5
Total Australia and Timor-Leste
10
904
161
*This asset is held-for-sale as of December 31, 2019.
 
See Note 5—Asset Acquisitions and Dispositions, in the Notes
 
to Consolidated Financial
Statements, for additional information.
 
 
Australia Pacific LNG
Australia Pacific LNG Pty Ltd (APLNG), our
 
joint venture with Origin Energy Limited and China
Petrochemical Corporation (Sinopec), is focused
 
on producing CBM from the Bowen and Surat
 
basins in
Queensland, Australia,
 
to supply the domestic gas market and convert
 
the CBM into LNG for export.
 
Origin
operates APLNG’s upstream production and pipeline system, and we operate
 
the downstream LNG facility,
located on Curtis Island near Gladstone, Queensland,
 
as well as the LNG export sales business.
 
 
We operate two fully subscribed 4.5-million-metric-tonnes-per-year LNG trains.
 
Approximately 3,900 net
wells are ultimately expected to supply both the
 
LNG sales contracts and domestic gas market.
 
The wells are
supported by gathering systems, central gas processing
 
and compression stations, water treatment
 
facilities,
and an export pipeline connecting the gas fields
 
to the LNG facilities.
 
The LNG is being sold to Sinopec under
20-year sales agreements for 7.6 million metric
 
tonnes of LNG per year, and Japan-based Kansai Electric
Power Co., Inc. under a 20-year sales agreement
 
for approximately 1 million metric
 
tonnes of LNG per year.
 
 
As of December 31, 2019, APLNG has an outstanding
 
balance of $6.7 billion on a $8.5 billion
 
project finance
facility.
 
In late 2018 and early 2019, APLNG successfully
 
refinanced $4.6 billion of the project finance
facility through three separate transactions,
 
which added lower cost United States Private
 
Placement (USPP)
bond and commercial bank facilities.
 
In conjunction with these transactions, APLNG
 
made voluntary
repayments of $2.2 billion to a syndicate of
 
Australian and international commercial banks
 
and fully
extinguished $2.4 billion of financing from the
 
Export-Import Bank of China.
 
Project finance interest
payments are bi-annual, concluding September
 
2030.
 
For additional information, see Note 3—Variable Interest Entities,
 
Note 6—Investments, Loans and Long-
Term Receivables and Note 12—Guarantees, in the Notes to Consolidated
 
Financial Statements.
 
 
 
 
 
 
 
13
Bayu-Undan
The Bayu-Undan gas condensate field is
 
located in the Timor Sea Joint Petroleum Development Area between
Timor-Leste and Australia.
 
We also operate and own a 56.9 percent interest in the associated Darwin LNG
Facility, located at Wickham Point, Darwin.
 
The Bayu-Undan natural gas recycle facility
 
processes wet gas; separates, stores and offloads condensate,
propane and butane; and re-injects dry gas back
 
into the reservoir.
 
In addition, a 310-mile natural gas pipeline
connects the facility to the 3.5-million-metric-tonnes-per-year
 
capacity Darwin LNG Facility.
 
Produced
natural gas is piped to the Darwin LNG Plant, where
 
it is converted into LNG before being transported
 
to
international markets.
 
In 2019, we sold 133 billion gross cubic feet
 
of LNG primarily to utility customers
 
in
Japan.
 
Athena/Perseus
The Athena production license (WA-17-L) in which we had a 50 percent working interest is located
 
offshore
Western Australia and our entitlement to production ended in the fourth quarter of 2019.
 
Annualized average
production from this license was five MBOED in
 
2019.
 
 
 
Exploration
We operate three exploration permits in the Browse Basin, offshore northwest Australia, in which
 
we own a 40
percent interest in permits WA-315-P,
 
WA-398-P and TP 28, of the Greater Poseidon
 
Area.
 
Phase I of the
Browse Basin drilling campaign resulted in
 
three discoveries in the Greater Poseidon Area and
 
Phase II
resulted in five additional discoveries.
 
All wells have been plugged and abandoned.
 
 
We operate two retention leases in the Bonaparte Basin, offshore northern Australia, where we
 
own a 37.5
percent interest in the Barossa and Caldita discoveries.
 
In April 2018, Barossa entered the FEED phase
 
of
development which continued
 
through 2019.
 
During the FEED phase, costs and the technical
 
definition for the
project will be finalized, gas and condensate sales
 
agreements progressed, and access arrangements
 
negotiated
with the owners of the Darwin LNG Facility
 
and Bayu-Darwin Pipeline.
 
In December 2019, we entered into an agreement
 
with 3D Oil to acquire a 75 percent interest
 
and operatorship
of an offshore Tasmanian Permit located in the Otway Basin.
 
The farm-in agreement is conditional upon the
agreement and signing of a JOA by both parties
 
and required government approvals.
 
We plan to conduct a 3D
seismic survey in the second half of 2020.
 
This activity is excluded from the dispositions
 
discussed below.
 
Dispositions
In the second quarter of 2019, we completed the sale
 
of our 30 percent interest in the Greater Sunrise
 
Fields to
the government of Timor-Leste.
 
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos with an expected completion
 
date in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent.
 
These subsidiaries hold our 37.5 percent interest
 
in the
Barossa Project and Caldita Field, our 56.9 percent
 
interest in the Darwin LNG Facility and Bayu-Undan
Field, our 40 percent interest in the Greater
 
Poseidon Fields, and our 50 percent interest
 
in the Athena Field.
 
Production associated with the Australia-West assets to be sold was 48 MBOED in
 
2019.
 
 
For additional information on these transactions,
 
see Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
14
Indonesia
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
South Sumatra
54
%
ConocoPhillips
2
321
56
Total Indonesia
2
321
56
 
 
During 2019, we operated
 
three PSCs in Indonesia:
 
the Corridor Block and South Jambi “B,” both
 
located in
South Sumatra, and Kualakurun in Central
 
Kalimantan.
 
Currently, we have production from the Corridor
Block.
 
 
South Sumatra
The Corridor PSC consists
 
of two oil fields and seven producing natural gas fields.
 
Natural gas is supplied
from the Grissik and Suban gas processing
 
plants to the Duri steamflood in central Sumatra
 
and to markets in
Singapore, Batam and West Java.
 
In 2019, we were awarded a 20-year extension,
 
with new terms, of the
Corridor PSC.
 
Under these terms, we retain a majority
 
interest and continue as operator for at least
 
three years
after 2023 and retain a participating interest
 
until 2043.
 
Production from the South Jambi “B” PSC has reached
 
depletion and field development has been suspended.
 
This PSC expired
 
on January 26, 2020 and has been returned to
 
the Government of Indonesia.
 
 
Exploration
 
We hold a 60 percent working interest in the Kualakurun PSC.
 
After completion of prospect evaluation,
 
we
and the other joint venture partners decided to relinquish
 
all of the remaining acreage to the Government
 
of
Indonesia.
 
 
Transportation
We are a 35 percent owner of a consortium company that has a 40 percent ownership
 
in PT Transportasi Gas
Indonesia, which owns and operates the Grissik
 
to Duri and Grissik to Singapore natural
 
gas pipelines.
 
China
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Penglai
49.0
%
CNOOC
29
-
29
Panyu
24.5
CNOOC
6
-
6
Total China
35
-
35
 
 
Penglai
The
 
Penglai
 
19-3,
 
19-9
 
and
 
25-6
 
fields
 
are
 
located
 
in
 
Bohai
 
Bay
 
Block
 
11/05
 
and
 
are
 
in
 
various
 
stages
 
of
development.
 
As
 
part
 
of
 
further
 
development
 
of
 
the
 
Penglai
 
19-9
 
Field,
 
the
 
wellhead
 
platform
 
J
 
Project
 
achieved
 
first
production in 2016.
 
This project will
 
include 62 wells,
 
57 of
 
which have
 
been completed and
 
brought online
through December 2019.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15
The
 
Penglai
 
19-3/19-9
 
Phase
 
3
 
Project
 
consists
 
of
 
three
 
new
 
wellhead
 
platforms
 
and
 
a
 
central
 
processing
platform.
 
First oil from Phase 3 was achieved in 2018 for two of
 
the platforms, with the third platform planned
to come
 
online in
 
the second
 
quarter of
 
2020.
 
This project
 
could include
 
up to
 
186 wells,
 
42 of
 
which have
been completed and brought online through December
 
2019.
 
 
In December 2018, we sanctioned the Penglai 25-6
 
Phase 4A Project.
 
This project consists of one new
wellhead platform and anticipates 62 new wells.
 
First production is expected in 2021.
 
 
Panyu
Our production license for Panyu 4-2, 5-1 and
 
11-6 located in Block 15/34 in the South China Sea expired
 
in
September 2019.
 
Annualized average production from these licenses
 
were six MBOED in 2019.
 
We still have a license for Panyu 4-1 in Block 15/34 and are evaluating this area for potential
 
development.
 
Exploration
Exploration activities in the Bohai Penglai Field during
 
2019 consisted of two successful appraisal
 
wells, a
full-field 3-D seismic program covering existing and
 
future development opportunities, and an infill
compressive seismic imaging (CSI) survey to improve
 
imaging beneath the gas cloud in support
 
of future
development projects.
 
In Block 15/34,
 
one exploration well was drilled in the Panyu
 
4-1E prospect and was
expensed as a dry hole.
 
Malaysia
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Gumusut
29.0
%
Shell
23
-
23
Kebabangan (KBB)
30.0
KPOC
3
91
18
Malikai
35.0
Shell
15
-
15
Siakap North-Petai
21.0
PTTEP
1
-
1
Total Malaysia
42
91
57
 
We have varying stages of exploration, development and production activities across
 
2.2 million net acres in
Malaysia, with working interests in six PSCs.
 
Three of these PSCs are located off the eastern Malaysian
 
state
of Sabah: Block G, Block J and the Kebabangan
 
Cluster (KBBC).
 
We operated
 
three exploration blocks,
Block SK304, Block SK313 and Block WL4-00,
 
off the eastern Malaysian state of Sarawak.
 
Block J
Gumusut
First production from the Gumusut Field occurred
 
from an early production system in
 
2012.
 
Production from
a permanent, semi-submersible Floating Production
 
System was achieved in 2014.
 
We currently have a 29
percent working interest in the Gumusut Field following
 
the redetermination of the Block J and Block
 
K
Malaysia Unit in 2017.
 
Gumusut Phase 2 first oil was achieved in 2019.
 
 
KBBC
The KBBC PSC grants us a 30 percent working
 
interest in the KBB, Kamunsu East and Kamunsu
 
East
Upthrown Canyon gas and condensate fields.
 
 
KBB
First production from the KBB gas field was
 
achieved in 2014.
 
During 2019, KBB tied-in to a nearby third-
party floating LNG vessel which provided increased
 
gas offtake capacity.
 
Production in 2020 is anticipated to
be impacted between 15 to 20 MBOED due to the
 
rupture of a third-party pipeline, in January 2020,
 
which
 
 
 
 
 
 
 
 
 
 
 
 
 
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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.