1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities
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chapter).
Emerging growth company
2
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.
☐
Item 8.01 Other Events.
ConocoPhillips (the “Company”) is recasting certain financial information included in its 2019
Annual Report on Form 10-K (the “Form 10-K”) which was initially filed with the Securities and
Exchange Commission (“SEC”) on February 18, 2020, to reflect a realignment of the Company’s
segments. The Company managed operations through six operating segments, which are primarily
defined by geographic region, and were previously named the following: Alaska; Lower 48;
Canada; Europe and North Africa; Asia Pacific and Middle East; and Other International.
Effective with the third quarter of 2020, the Company has restructured segments to align with
changes within its internal organization. The Middle East business was realigned from the Asia
Pacific and Middle East segment to the Europe and North Africa segment. The segments have
been renamed the Asia Pacific segment and the Europe, Middle East and North Africa segment.
Attached as Exhibit 99.1 of this Current Report on Form 8-K are the following portions of the
Form 10-K which were revised to reflect this realignment in segments: Business and Properties
(Items 1 and 2), Management’s Discussion and Analysis of Financial Condition and Results of
Operations (Item 7), Financial Statements and Supplementary Data (Item 8), and Exhibit, Financial
Statement Schedules (Item 15). The change in segments did not impact previously reported
consolidated net income (loss), net income (loss) attributable to ConocoPhillips, or net income
(loss) attributable to ConocoPhillips per share of common stock. The segment-specific information
presented in exhibit 99.1 is consistent with the presentation of segments in the Company’s
Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2020, filed with the
SEC on November 3, 2020.
This Current Report on Form 8-K is being filed only for the purposes described above and all
other information in the Form 10-K remains unchanged. In order to preserve the nature and
character of the disclosures set forth in the Form 10-K, the items included in Exhibit 99.1 of this
Current Report on Form 8-K have been updated solely for matters relating specifically to the
segment realignment and related classifications as described above. No attempt has been made in
this Current Report on Form 8-K to reflect events or occurrences after the date of the filing of the
Form 10-K, on February 18, 2020, and it should not be read to modify or update other
disclosures as presented in the Form 10-K. Therefore, this Current Report on Form 8-K should
be read in conjunction with the Form 10-K and the Company’s filings made with the SEC
subsequent to the filing of the Form 10-K, including the Company’s Quarterly Reports on Form
10-Q for the quarters ended March 31, 2020, June 30, 2020, and September 30, 2020. These
subsequent SEC filings contain important information regarding events, risks, developments and
updates affecting the Company and its expectations that have occurred since the filing of the
Form 10-K. The revised portions of the Form 10-K described above are attached as Exhibit 99.1
hereto and incorporated herein by reference. References in the attached exhibits to the Form 10-
K or parts thereof refer to the Form 10-K for the year ended December 31, 2019, filed on
February 18, 2020, except to the extent portions of such Form 10-K have been revised in this
Current Report on Form 8-K, in which case, they refer to the applicable revised portion in this
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Current Report on Form 8-K. The information contained herein is not an amendment to, or a
restatement of, the Form 10-K.
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Item 9.01 Financial Statements and Exhibits.
(d)
Exhibits
Exhibit No. Description
23.1*
23.2*
99.1*
99.2*
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 filed
herewith).
* Filed herewith
** These interactive data files are furnished and deemed not filed or part of a registration
statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as
amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of
1934, as amended, and otherwise are not subject to liability under those sections.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
CONOCOPHILLIPS
/s/
Catherine A. Brooks
(Chief Accounting and Duly Authorized Officer)
November 16, 2020
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
We consent to the incorporation by reference in the following Registration Statements:
●
ConocoPhillips Form S-3 File No. 333-240978
●
ConocoPhillips Form S-4 File No. 333-130967
●
ConocoPhillips Form S-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
of our report dated February 18, 2020, except as it relates to the effects of the change in segments
described in Note 25, as to which the date is November 16, 2020, with respect to the consolidated
financial statements (including condensed consolidating financial information and financial statement
schedule) of ConocoPhillips and our report dated February 18, 2020, with respect to the effectiveness of
internal control over financial reporting of ConocoPhillips, included in this Current Report on Form 8-K.
/s/ Ernst & Young LLP
Houston, Texas
November 16, 2020
Exhibit 23.2
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
November 16, 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’ Current Report on
Form 8-K Exhibit 99.1, with respect to the sections under “Item 8. Financial Statements and Supplementary
Data” and subheading “Reserves Governance” and under “Item 15. Exhibits, Financial Statement Schedules”
and to the inclusion of our process review letter report dated February 18, 2020 (our Report), as exhibit 99.2
to ConocoPhillips’ Current Report on Form 8-K. We also consent to the incorporation by reference of our
Report in the Registration Statements filed by ConocoPhillips on Form S-3 (File No. 333-240978), Form S-4
(File 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
1
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 in our 2019 Annual Report on Form 10-K and
“CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 60.
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
We manage our operations through six operating segments, defined by geographic region: Alaska; Lower 48;
Canada; Europe, Middle East and North Africa; Asia Pacific and Other International. Effective with the third
quarter of 2020, we have restructured our segments to align with changes to our internal organization. The
Middle East business was realigned from the Asia Pacific and Middle East segment to the Europe and North
Africa segment. The segments have been renamed the Asia Pacific segment and the Europe, Middle East and
North Africa segment. We have revised segment information disclosures and segment performance metrics
presented within our results of operations for the current and prior years. 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.
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The information listed below appears in the “Oil and Gas Operations” disclosures following the Notes to
Consolidated Financial Statements and is incorporated herein by reference:
●
Proved worldwide crude oil, NGLs, natural gas and bitumen reserves.
●
Net production of crude oil, NGLs, natural gas and bitumen.
●
Average sales prices of crude oil, NGLs, natural gas and bitumen.
●
Average production costs per BOE.
●
Net wells completed, wells in progress and productive wells.
●
Developed and undeveloped acreage.
The following table is a summary of the proved reserves information included in the “Oil and Gas Operations”
disclosures following the Notes to Consolidated Financial Statements. Approximately 80 percent of our
proved reserves are 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.
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.
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
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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 consolidated 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.
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.
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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.
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.
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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 41 percent of our consolidated liquids production
and 35 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
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
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.
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
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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.
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.
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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.
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
consolidated liquids production and less than 1 percent of our natural gas production.
2019
Liquids
Natural 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
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.
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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.
EUROPE, MIDDLE EAST AND NORTH AFRICA
The Europe, Middle East and North Africa segment consisted of operations in Norway, Qatar, Libya and the
U.K. and exploration activities in Norway and Libya. In 2019, operations in Europe, Middle East and North
Africa contributed 17 percent of our consolidated liquids production and 27 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.
9
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.
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
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.
10
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.
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.
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
blockade of the Es Sider crude oil export terminal and the declaration of Force Majeure by the National Oil
Corporation of Libya.
ASIA PACIFIC
The Asia Pacific segment has exploration and production operations in China, Indonesia, Malaysia and
Australia and producing operations in Timor-Leste. In 2019, operations in the Asia Pacific segment
contributed 10 percent of our consolidated liquids production and 36 percent of natural gas production.
11
Australia and Timor-Leste
2019
Natural
Liquids
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.
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.
12
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.
Indonesia
2019
Natural
Liquids
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.
13
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 Pengl ai 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.
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.
14
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
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.
15
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.
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.
16
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
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
17
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
®
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.
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.
18
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.
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 50 through 55 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 8-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
.
19
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 60.
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
20
our value proposition, as evidenced by the results discussed below, positions us for success in an environment
of price uncertainty and ongoing volatility.
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.
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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 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, Middle East 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 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 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,
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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
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.
23
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.
●
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 beginning on page 21 in our 2019 Annual Report on Form 10-K
“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
24
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.
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.
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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:
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
26
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
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, Middle East and North Africa; Asia Pacific 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.
27
RESULTS OF OPERATIONS
Effective with the third quarter of 2020, we have restructured our segments to align with changes to our
internal organization. The Middle East business was realigned from the Asia Pacific and Middle East segment
to the Europe and North Africa segment. The segments have been renamed the Asia Pacific segment and the
Europe, Middle East and North Africa segment. We have revised segment information disclosures and
segment performance metrics presented within our results of operations for the current and prior years.
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, Middle East and North Africa
3,170
2,594
1,116
Asia Pacific
1,483
1,342
(1,661)
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
Europe, Middle East and North Africa 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.
28
2018 vs. 2017
Net income attributable to ConocoPhillips increased $7,112 million in 2018. The increase was mainly due to:
●
Higher realized commodity prices on a more liquids-weighted portfolio.
●
The absence of a combined $2.5 billion after-tax impairment related to the sale of our interests in the
San Juan Basin and the marketing of our Barnett asset, recognized in the second quarter of 2017.
●
The absence of a $2.4 billion before- and after-tax impairment of our equity investment in Australia
Pacific LNG Pty Ltd (APLNG), recognized in the second quarter of 2017.
●
Recognition of $774 million after-tax gain on the Clair disposition in the United Kingdom, in the
fourth quarter of 2018.
●
Lower depreciation, depletion and amortization (DD&A) expense, mainly due to lower unit-of-
production rates from reserve revisions and disposition impacts.
●
Recognition of $417 million after-tax in other income from a settlement agreement with PDVSA in
2018.
●
Lower exploration expenses, primarily due to the absence of first quarter 2017 charges in our Lower
48 and Other International segments.
●
Lower interest and debt expense because of a lower debt balance.
●
Higher equity earnings in QG3 and APLNG, primarily due to higher realized LNG prices, partly offset
by the absence of volumes in 2018 related to the disposition of our interest in the FCCL Partnership in
Canada in 2017.
These increases in net income were partly offset by:
●
The absence of $1.6 billion in after-tax gains related to the sale of certain Canadian assets in 2017.
●
The absence of a $996 million deferred tax benefit related to the disposition of certain Canadian
assets, recognized in the first quarter of 2017.
●
The absence of deferred tax benefits totaling $852 million related to the Tax Legislation enacted on
December 22, 2017.
●
An unrealized loss of $437 million on our Cenovus Energy common shares in 2018.
●
The absence of a $337 million after-tax award, including interest, from an arbitration settlement with
The Republic of Ecuador in 2017.
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 Europe, Middle East and North Africa
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.
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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.
2018 vs. 2017
Sales and other operating revenues increased 25 percent in 2018, due to higher realized commodity prices,
mainly crude oil, on a portfolio with a higher mix of crude oil and less of bitumen and natural gas. Partly
offsetting this increase, were lower natural gas volumes sold due to 2017 dispositions in the Lower 48 and
Canada.
Equity in earnings of affiliates increased $302 million in 2018. The increase in equity earnings was primarily
due to higher earnings from QG3 and APLNG as a result of higher LNG prices for both affiliates and higher
oil prices in QG3. Partly offsetting this increase, was the absence of equity in earnings resulting from the
disposition of our investment in the FCCL Partnership in 2017.
Gain on dispositions decreased $1,114 million in 2018. The decrease was primarily due to the absence of a
$2.1 billion before-tax gain on the sale of certain Canadian assets recognized in 2017, partly offset by a $715
million before-tax gain recognized in the fourth quarter of 2018 on 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 United Kingdom.
For additional information concerning gain on dispositions, see Note 5—Asset Acquisitions and Dispositions,
in the Notes to Consolidated Financial Statements.
Other income decreased $356 million in 2018, mainly due to a $437 million unrealized loss on our Cenovus
Energy common shares in 2018 and the absence of a $337 million arbitration settlement, including interest,
with The Republic of Ecuador in 2017. Partly offsetting the decrease, was $430 million before-tax from a
settlement agreement with PDVSA in 2018.
30
For discussion of our Cenovus Energy shares, see Note 7—Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements. For discussion of our Ecuador and PDVSA settlements, see Note 13—
Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Purchased commodities increased 15 percent in 2018, mainly due to higher crude oil volumes purchased and
higher crude oil prices.
Production and operating expenses increased 1 percent in 2018, primarily due to costs associated with higher
underlying production volumes as well as higher maintenance and wellwork, largely offset by the absence of
costs resulting from 2017 dispositions in our Canada and Lower 48 segments.
Exploration expenses decreased $565 million in 2018, primarily as a result of lower dry hole costs, leasehold
impairment expense and other exploration expenses.
Dry hole costs were reduced primarily due to the absence of before-tax charges of $288 million for multiple
Shenandoah wells in the deepwater Gulf of Mexico, including wells previously suspended. These charges
were reflected in our Lower 48 segment during 2017.
Leasehold impairment expense was reduced mainly due to the absence of before-tax charges of $51 million for
Shenandoah and $38 million for certain Lower 48 mineral assets, both recognized in 2017.
Other exploration expenses were reduced mainly due to the absence of a $43 million before-tax charge for the
cancellation of our Athena drilling rig contract and other rig stacking costs in our Other International segment
in 2017.
For additional information on leasehold impairments and other exploration expenses, see Note 8—Suspended
Wells and Other Exploration Expenses, and Note 9—Impairments, in the Notes to Consolidated Financial
Statements.
DD&A decreased $889 million in 2018, mainly due to lower unit-of-production rates from positive reserve
revisions and impacts from the 2017 dispositions in our Canada and Lower 48 segments, partly offset by
increased underlying production volumes.
Impairments decreased $6.6 billion in 2018, mainly due to the absence of 2017 impairments of $3.9 billion
before-tax related to our former interests in the San Juan Basin and the Barnett, both in our Lower 48 segment,
as well as a $2.4 billion before- and after-tax impairment of our equity investment in APLNG. For additional
information, see Note 6—Investments, Loans and Long-Term Receivables and Note 9—Impairments, in the
Notes to Consolidated Financial Statements.
Taxes other than income taxes increased $239 million in 2018, primarily due to higher production taxes in
Alaska and the Lower 48 corresponding with higher realized commodity prices.
Interest and debt expense decreased $363 million in 2018, primarily due to lower debt balances.
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax provision (benefit) and effective tax rate.
31
Summary Operating Statistics
2019
2018
2017
Average Net Production
Crude oil (MBD)
Consolidated Operations
692
639
585
Equity affiliates
13
14
14
Total crude oil
705
653
599
Natural gas liquids (MBD)
Consolidated Operations
107
95
104
Equity affiliates
8
7
7
Total natural gas liquids
115
102
111
Bitumen (MBD)
Consolidated Operations
60
66
59
Equity affiliates
63
Total bitumen
60
66
122
Natural gas (MMCFD)
Consolidated Operations
1,753
1,743
2,263
Equity affiliates
1,052
1,031
1,007
Total natural gas
2,805
2,774
3,270
Total Production
1,348
1,283
1,377
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated Operations
$
60.98
68.03
51.89
Equity affiliates
61.32
72.49
54.76
Total crude oil
60.99
68.13
51.96
Natural gas liquids (per bbl)
Consolidated Operations
18.73
29.03
24.21
Equity affiliates
36.70
45.69
38.74
Total natural gas liquids
20.09
30.48
25.22
Bitumen (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)
Consolidated Operations
4.25
5.40
3.97
Equity affiliates
6.29
6.06
4.27
Total natural gas
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
32
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.
2018 vs. 2017
Total production, including Libya, of 1,283 MBOED decreased 7 percent in 2018 compared with 2017,
primarily due to:
• Disposition impacts from asset sales in Canada and the Lower 48 in 2017.
• Normal field decline.
• Higher unplanned downtime, including a third-party pipeline outage in Malaysia in 2018.
The decrease in production during 2018 was partly offset by:
• New wells online, primarily from tight oil plays in the Lower 48 and Malikai in Malaysia.
• Improved drilling and well performance in Alaska, Norway, Lower 48 and China.
• The continued rampup in Libya.
Production excluding Libya was 1,242 MBOED in 2018 compared with 1,356 MBOED in 2017. The volume
from closed dispositions was approximately 200 MBOED in 2017 and 15 MBOED in 2018. The volume from
acquisitions was less than 10 MBOED in 2018. Our underlying production, which excludes the full-year
impact of acquisitions, dispositions, and Libya, increased over 5 percent in 2018 compared with 2017.
33
Alaska
2019
2018
2017
Net Income Attributable to ConocoPhillips
$
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
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 consolidated 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.
2018 vs. 2017
Alaska reported earnings of $1,814 million in 2018, compared with earnings of $1,466 million in 2017. The
increase in earnings was mainly due to higher realized crude oil prices. Additionally, earnings were improved
due to the absence of a $110 million after-tax impairment related to our small interest in the Point Thomson
Unit, recognized in the first quarter of 2017; a $98 million reduction in tax valuation allowance, recognized in
the fourth quarter of 2018; lower DD&A expense from reserve additions; and a $79 million after-tax benefit
resulting from an accrual reduction due to a transportation cost ruling by the Federal Energy Regulatory
Commission (FERC), recorded in the first quarter of 2018. Partly offsetting these increases in earnings, was
the absence of an $892 million tax benefit from the revaluation of allocated U.S. deferred taxes at a lower
federal statutory rate, in accordance with the Tax Legislation enacted in 2017.
34
Consolidated production increased 2 percent in 2018 compared with 2017, primarily due to improved drilling
and well performance, 8 MBOED from acquisitions in the Western North Slope and the Greater Kuparuk
Area, and the startup of GMT-1 in the fourth quarter of 2018, partly offset by normal field decline.
Acquisitions
During the second quarter of 2018, we obtained regulatory approvals and completed a transaction with
Anadarko Petroleum Corporation to acquire its 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. In 2018, our Alaska segment net production included 7 MBOED associated with the additional
interest acquired. In addition, we now have 100 percent interest in approximately 1.2 million acres of
exploration and development lands, including the Willow Discovery.
In December of 2018, we completed a transaction with BP to acquire their nonoperated interest in the Kuparuk
Assets in Alaska, and to sell a ConocoPhillips subsidiary to BP, which held 16.5 percent of our 24 percent
interest in the BP-operated Clair Field in the United Kingdom. In 2018, our Alaska segment net production
included 1 MBOED related to the additional interest acquired in the Greater Kuparuk Area. See Note 5—
Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements, for additional
information.
Lower 48
2019
2018
2017
Net Income (Loss) Attributable to ConocoPhillips
$
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
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 41 percent of our consolidated liquids production and 35 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.
35
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-
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.
2018 vs. 2017
Lower 48 reported earnings of $1,747 million in 2018, compared with a net loss of $2,371 million in 2017.
Earnings increased primarily due to the absence of a combined $2.5 billion after-tax impairment related to the
sale of our interests in the San Juan Basin and the marketing of our Barnett asset, recognized in the second
quarter of 2017; higher realized crude oil and NGL prices; higher crude oil sales volumes; lower DD&A
expense, primarily due to reserve additions and asset disposition impacts, partly offset by higher underlying
volumes; lower exploration expenses and higher gain on dispositions related to noncore asset sales. The
increase in earnings was partly offset by lower natural gas sales volumes, primarily due to the disposition of
our interests in the San Juan Basin in 2017.
In 2018, our average realized crude oil price of $62.99 per barrel was 3 percent less than WTI of $64.92 per
barrel. The differential was driven primarily by local market dynamics in the Gulf Coast, Bakken and Permian
Basin.
Consolidated production decreased 1 percent in 2018 compared with 2017. The decrease was mainly
attributable to normal field decline and disposition impacts related to interests sold in the San Juan Basin and
36
other noncore assets. Adjusted for the impact of dispositions of 82 MBOED in 2017, underlying production
increased approximately 25 percent in 2018 compared with 2017, primarily due to new production from
unconventional assets in the Eagle Ford, Bakken and Permian Basin.
Asset Dispositions
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 for net proceeds of $105 million. 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. This transaction was recorded at fair value resulting in the
recognition of a $44 million after-tax 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.
In the fourth quarter of 2018, we completed the sale of our interests in the Barnett to Lime Rock Resources for
$196 million after customary adjustments. Production associated with the Barnett averaged 8 MBOED in
2018, of which approximately 55 percent was natural gas and 45 percent was natural gas liquids. After-tax
impairment charges of $69 million were recognized during 2018.
On July 31, 2017, we completed the sale of our interests in the San Juan Basin for total proceeds comprised of
$2.5 billion in cash after customary adjustments and 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 million British thermal units. During 2018, we recorded gains
on dispositions for these contingent payments of $28 million.
On September 29, 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash
after customary adjustments.
See Note 5—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements, for
additional information.
37
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
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 consolidated
liquids production and less than one percent of our consolidated 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
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.
38
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.
2018 vs. 2017
Canada operations reported earnings of $63 million in 2018 compared with $2,564 million in 2017. The
decrease was mainly due to the absence of a $1.6 billion after-tax gain on the sale of our interest in the FCCL
Partnership and western Canada gas assets and an associated $1.0 billion deferred tax benefit, and equity
earnings in the FCCL Partnership. For additional information on the Canada disposition, see Note 5—Asset
Acquisitions and Dispositions and Note 7—Investment in Cenovus Energy, in the Notes to Consolidated
Financial Statements.
Total average production decreased 95 MBOED in 2018 compared with 2017. The production decrease was
primarily due to our 2017 Canada disposition, partly offset by strong well performance at Surmont.
Acquisition
In February 2018, we acquired approximately 34,500 net acres of undeveloped land in the Montney for a net
purchase price of approximately $120 million. The additional acreage is adjacent to our existing position in
the liquids-rich portion of the Montney.
Europe, Middle East and North Africa
2019
*
2018
*
2017
*
Net Income Attributable to ConocoPhillips
$
3,170
2,594
1,116
Consolidated Operations
Average Net Production
Crude oil (MBD)
138
149
142
Natural gas liquids (MBD)
7
8
8
Natural gas (MMCFD)
478
503
484
Total Production
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
*Prior periods have been updated to reflect the Middle East Business Unit moving from Asia Pacific to the Europe, Middle East and North
Africa segment. See Note 25—Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements for additional
information.
The Europe, Middle East and North Africa segment consisted of operations principally located in the
Norwegian and U.K. sectors of the North Sea, the Norwegian Sea, Qatar and Libya. In 2019, our Europe,
39
Middle East and North Africa operations contributed 17 percent of our consolidated liquids production and 27
percent of our natural gas production.
2019 vs. 2018
Earnings for Europe, Middle East and North Africa operations of $3,170 million increased $576 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 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; lower earnings in equity
affiliates, primarily due to a deferred tax adjustment at QG3 that resulted in a $118 million reduction to equity
earnings; and lower realized natural gas and crude oil prices.
Consolidated production decreased 7 percent 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.
2018 vs. 2017
Earnings for Europe, Middle East and North Africa operations of $2,594 million increased $1,478 million in
2018 compared to 2017. Earnings in 2018 included a $774 million 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 United Kingdom. Earnings were also improved due to higher realized crude oil and natural gas
prices; increased equity earnings due to higher LNG prices at QG3; and lower DD&A expense, primarily due
to reserve additions.
Consolidated production increased 5 percent in 2018, compared with 2017. The increase was mainly due to
higher production in Libya and new wells online in Norway and the United Kingdom. These increases in
production were partly offset by normal field decline and the final cessation of production in several producing
gas fields in the Southern North Sea in the third quarter of 2018. Production associated with the Southern
North Sea was 22 million cubic feet a day or 4 MBOED in 2018.
Disposition
In the fourth quarter of 2018, we completed a transaction to sell a ConocoPhillips subsidiary to BP, which held
16.5 percent of our 24 percent interest in the BP-operated Clair Field in the United Kingdom and acquire their
nonoperated interest in the Kuparuk Assets in Alaska. In 2018, our Europe, Middle East and North Africa
segment net production associated with the disposed 16.5 percent interest in the Clair Field was approximately
5 MBOED. We recognized a $774 million after-tax gain in the fourth quarter related to this transaction, as
discussed above. See Note 5—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial
Statements, for additional information.
40
Asia Pacific
2019
*
2018
*
2017
*
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
1,483
1,342
(1,661)
Consolidated Operations
Average Net Production
Crude oil (MBD)
85
89
93
Natural gas liquids (MBD)
4
3
4
Natural gas (MMCFD)
637
626
687
Total Production
196
196
212
Average Sales Prices
Crude oil (dollars per bbl)
$
65.02
70.93
54.38
Natural gas liquids (dollars per bbl)
37.85
47.20
41.37
Natural gas (dollars per mcf)
5.91
6.15
4.98
*Prior periods have been updated to reflect the Middle East Business Unit moving from Asia Pacific to the Europe, Middle East and North Africa
segment. See Note 25—Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements for additional
information.
The Asia Pacific segment has operations in China, Indonesia, Malaysia, Australia and Timor-Leste. During
2019, Asia Pacific contributed 10 percent of our consolidated liquids production and 36 percent of our natural
gas production.
2019 vs. 2018
Asia Pacific reported earnings of $1,483 million in 2019, compared with $1,342 million in 2018. The increase in
earnings was mainly due to 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.
Partly offsetting this increase in earnings was lower realized crude oil, NGL and natural gas prices and lower
LNG and crude oil sales volumes.
Consolidated production was flat in 2019 compared with 2018. There were increases 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.
Offsetting these production increases 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
41
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.
2018 vs. 2017
Asia Pacific reported earnings of $1,342 million in 2018, compared with a loss of $1,661 million in 2017. The
increase in earnings was mainly due to the absence of a $2,384 million before- and after-tax charge for the
impairment of our APLNG investment in 2017, higher realized commodity prices, and increased equity in
earnings of affiliates, mainly due to higher LNG prices at APLNG. See the “APLNG” section of Note 6—
Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for
information on the 2017 impairment of our APLNG investment.
Consolidated production decreased 8 percent in 2018, compared with 2017. The decrease was primarily due to
unplanned downtime in Malaysia related to the rupture of a third-party pipeline which carries gas production
from the Kebabangan gas field in Malaysia and normal field decline. This decrease was partly offset by new
wells online at Malakai in Malaysia and an infill drilling program in China.
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.
42
2018 vs. 2017
Other International operations reported earnings of $364 million in 2018, compared with earnings of $167
million in 2017. The increase in earnings was primarily due to recognizing $417 million after-tax in other
income under a settlement agreement with PDVSA associated with an arbitration award issued by the ICC.
Partly offsetting the increase in earnings, was the absence of a $320 million after-tax award from an arbitration
settlement with The Republic of Ecuador in 2017. See Note 13—Contingencies and Commitments in the
Notes to Consolidated Financial Statements, for additional information.
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.
43
2018 vs. 2017
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net
interest decreased $59 million in 2018 compared with 2017, primarily due to less interest from lower debt
balances, higher capitalized interest on projects, and an accrual reduction due to a transportation cost ruling by
the FERC in the first quarter of 2018. Partly offsetting these impacts, were reduced tax benefits on interest
expense following the Tax Legislation, which lowered the U.S. corporate income tax rate from 35 percent to
21 percent effective January 1, 2018, and a lower tax benefit due to higher interest from the fair market value
method of apportioning interest expense in the United States.
Corporate general and administrative expenses include compensation programs and staff costs. These costs
decreased by $102 million in 2018 compared with 2017, primarily due to lower staff expenses and costs
associated with certain key employee compensation programs.
Technology includes our investment in new technologies or businesses, as well as licensing revenues.
Activities are focused on tight oil reservoirs, LNG, oil sands and other production operations. Earnings from
Technology increased by $89 million in 2018 compared with 2017, 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. Losses in “Other” decreased by $219 million in 2018 compared with 2017,
primarily due to the absence of an $813 million tax charge from the revaluation of deferred taxes at a lower
federal statutory rate, in accordance with the Tax Legislation enacted in 2017; lower premiums on the early
retirement of debt; partly offset by a $437 million unrealized loss on our Cenovus Energy common shares.
44
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.
45
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, Middle East and North Africa and 12 percent from Asia Pacific.
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
46
payment of $75 million upon final investment decision of the Barossa development project. Also 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. 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.
47
Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions
requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters
of credit as collateral. At December 31, 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 beginning on page 21 in our 2019 Annual Report on Form 10-K, “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.
48
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
Years
Years
After
Total
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.
49
(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, Middle East and North Africa
708
877
872
Asia Pacific
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.
50
Contingencies
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed
against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the
placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active
and inactive sites. We regularly assess the need for accounting recognition or disclosure of these
contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a
liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be
reasonably estimated and no amount within the range is a better estimate than any other amount, then the
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.
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●
U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires
facilities to report toxic chemical inventories with local emergency planning committees and response
departments.
●
U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground
injection wells.
●
U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S.
waters and impose liability for the cost of pollution cleanup resulting from operations, as well as
potential liability for pollution damages.
●
European Union Trading Directive resulting in European Emissions Trading Scheme.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water,
establish water quality limits and establish standards and impose obligations for the remediation of releases of
hazardous substances and hazardous wastes. They also, in most cases, require permits in association with new
or modified operations. These permits can require an applicant to collect substantial information in connection
with the application process, which can be expensive and time consuming. In addition, there can be delays
associated with notice and comment periods and the agency’s processing of the application. Many of the
delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws
and regulations governing these same types of activities. While similar, in some cases these regulations may
impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or
transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor
easily determinable as new standards, such as air emission standards and water quality standards, continue to
evolve. However, environmental laws and regulations, including those that may arise to address concerns
about global climate change, are expected to continue to have an increasing impact on our operations in the
U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission
compliance and remediation obligations in the U.S. and Canada.
An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of
oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal or
national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing
currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many
decades, a number of new laws, regulations and permitting requirements are under consideration by various
state environmental agencies, and others which could result in increased costs, operating restrictions,
operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions
on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas
investments. We have adopted operating principles that incorporate established industry standards designed to
meet or exceed government requirements. Our practices continually evolve as technology improves and
regulations change.
We also are subject to certain laws and regulations relating to environmental remediation obligations
associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their
state equivalents. Longer-term expenditures are subject to considerable uncertainty and may fluctuate
significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state
environmental agencies alleging we are a potentially responsible party under CERCLA or an equivalent state
statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by
private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various
sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of
December 31, 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.
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For most Superfund sites, our potential liability will be significantly less than the total site remediation costs
because the percentage of waste attributable to us, versus that attributable to all other potentially responsible
parties, is relatively low. Although liability of those potentially responsible is generally joint and several for
federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party
typically have had the financial strength to meet their obligations, and where they have not, or where
potentially responsible parties could not be located, our share of liability has not increased materially. Many of
the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies
concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion
responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain
a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state
agency approval. There are relatively few sites where we are a major participant, and given the timing and
amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all
CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial
condition.
Expensed environmental costs were $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.
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Climate Change
Continuing political and social attention to the issue of global climate change has resulted in a broad range of
proposed or promulgated state, national and international laws focusing on GHG reduction. These proposed or
promulgated laws apply or could apply in countries where we have interests or may have interests in the future.
Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for
implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a
material impact on our results of operations and financial condition. Examples of legislation 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
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.
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●
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.
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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
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$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
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.
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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
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
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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
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
59
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
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.
60
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.
●
Changes in international trade relationships, including the imposition of trade restrictions or tariffs
61
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 risk factors generally described in Item 1A—Risk Factors in our 2019 Annual Report on Form
10-K filed with the SEC on February 18, 2020, and any additional risks described in our other filings
with the SEC.
62
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
Page
Report of Management ............................................................................................................................
63
Reports of Independent Registered Public Accounting Firm..................................................................
64
Consolidated Income Statement for the years ended December 31, 2019, 2018 and 2017 ....................
68
Consolidated Statement of Comprehensive Income for the years ended
December 31, 2019, 2018 and 2017 ..................................................................................................
69
Consolidated Balance Sheet at December 31, 2019 and 2018 ................................................................
70
Consolidated Statement of Cash Flows for the years ended December 31, 2019, 2018 and 2017 .........
71
Consolidated Statement of Changes in Equity for the years ended
December 31, 2019, 2018 and 2017 ..................................................................................................
72
Notes to Consolidated Financial Statements ............................................................................................
73
Supplementary Information
Oil and Gas Operations ..............................................................................................................
137
Selected Quarterly Financial Data ..............................................................................................
165
Condensed Consolidating Financial Information .......................................................................
166
63
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
64
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.
65
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.
66
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, except as it relates to the effects of the change in segments described in Note 25, as to
which the date is November 16, 2020
67
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
68
Consolidated Income Statement
ConocoPhillips
Years Ended December 31
Millions of Dollars
2019
2018
2017
Revenues and Other Income
Sales and other operating revenues
$
Equity in earnings of affiliates
Gain on dispositions
Other income
Total Revenues and Other Income
Costs and Expenses
Purchased commodities
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
(17 )
Other expenses
Total Costs and Expenses
Income (loss) before income taxes
(2,615 )
Income tax provision (benefit)
(1,822 )
Net income (loss)
(793 )
Less: net income attributable to noncontrolling interests
(68 )
(48 )
(62 )
Net Income (Loss) Attributable to ConocoPhillips
$
(855 )
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
(0.70 )
Diluted
(0.70 )
Average Common Shares Outstanding
(in thousands)
Basic
Diluted
See Notes to Consolidated Financial Statements.
69
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years Ended December 31
Millions of Dollars
2019
2018
2017
Net Income (Loss)
$
(793 )
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period
(7 )
Reclassification adjustment for amortization of prior
service credit included in net income (loss)
(35 )
(40 )
(38 )
Net change
(35 )
(47 )
(36 )
Net actuarial gain (loss) arising during the period
(55 )
(150 )
Reclassification adjustment for amortization of net
actuarial losses included in net income (loss)
Net change
Nonsponsored plans*
(3 )
(1 )
(2 )
Income taxes on defined benefit plans
(2 )
(42 )
(81 )
Defined benefit plans, net of tax
Unrealized holding loss on securities
(58 )
Unrealized loss on securities, net of tax
(58 )
Foreign currency translation adjustments
(645 )
Income taxes on foreign currency translation adjustments
(4 )
Foreign currency translation adjustments, net of tax
(642 )
Other Comprehensive Income (Loss), Net of Tax
(603 )
Comprehensive Income (Loss)
(118 )
Less: comprehensive income attributable to noncontrolling interests
(68 )
(48 )
(62 )
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
(180 )
*Plans for which ConocoPhillips is not the primary obligor
—
primarily those administered by equity affiliates.
See Notes to Consolidated Financial Statements.
70
Consolidated Balance Sheet
ConocoPhillips
At December 31
Millions of Dollars
2019
2018
Assets
Cash and cash equivalents
$
Short-term investments
Accounts and notes receivable (net of allowance of $
and $
Accounts and notes receivable—related parties
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Loans and advances—related parties
Net properties, plants and equipment (net of accumulated depreciation, depletion
and amortization of $
Other assets
Total Assets
$
Liabilities
Accounts payable
$
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (
Issued (2019—
Par value
Capital in excess of par
Treasury stock (at cost: 2019—
(46,405 )
(42,905 )
Accumulated other comprehensive loss
(5,357 )
(6,063 )
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
$
See Notes to Consolidated Financial Statements.
71
Consolidated Statement of Cash Flows
ConocoPhillips
Years Ended December 31
Millions of Dollars
2019
2018
2017
Cash Flows From Operating Activities
Net income (loss)
$
(793 )
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation, depletion and amortization
Impairments
Dry hole costs and leasehold impairments
Accretion on discounted liabilities
Deferred taxes
(444 )
(3,681 )
Undistributed equity earnings
(232 )
Gain on dispositions
(1,966 )
(1,063 )
(2,177 )
Other
(1,000 )
(429 )
Working capital adjustments
Decrease (increase) in accounts and notes receivable
(886 )
Decrease (increase) in inventories
(67 )
(55 )
Decrease (increase) in prepaid expenses and other current assets
(55 )
Increase (decrease) in accounts payable
(378 )
(52 )
Increase (decrease) in taxes and other accruals
(676 )
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
(6,636 )
(6,750 )
(4,591 )
Working capital changes associated with investing activities
(103 )
(68 )
Proceeds from asset dispositions
Net sales (purchases) of investments
(2,910 )
(1,790 )
Collection of advances/loans—related parties
Other
(108 )
Net Cash Provided by (Used in) Investing Activities
(6,618 )
(3,843 )
Cash Flows From Financing Activities
Repayment of debt
(80 )
(4,995 )
(7,876 )
Issuance of company common stock
(30 )
(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
(46 )
(117 )
Net Change in Cash, Cash Equivalents and Restricted Cash
(789 )
(385 )
Cash, cash equivalents and restricted cash at beginning of period
Cash, Cash Equivalents and Restricted Cash at End of Period
$
Restricted cash of $
respectively, of our Consolidated Balance Sheet as of December 31, 2019.
Restricted cash totaling $
See Notes to Consolidated Financial Statements.
72
Consolidated Statement of Changes in Equity
Millions of Dollars
Attributable to ConocoPhillips
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-
Controlling
Interests
Total
December 31, 2016
$
(36,906 )
(6,193 )
Net income (loss)
(855 )
(793 )
Other comprehensive income
Dividends paid ($
(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
Other
December 31, 2017
$
(39,906 )
(5,518 )
Net income
Other comprehensive loss
(603 )
(603 )
Dividends paid ($
(1,363 )
(1,363 )
Repurchase of company common stock
(2,999 )
(2,999 )
Distributions to noncontrolling interests and other
(121 )
(121 )
Distributed under benefit plans
Changes in Accounting Principles*
(278 )
(220 )
Other
December 31, 2018
$
(42,905 )
(6,063 )
Net income
Other comprehensive income
Dividends paid ($
(1,500 )
(1,500 )
Repurchase of company common stock
(3,500 )
(3,500 )
Distributions to noncontrolling interests and other
(128 )
(128 )
Distributed under benefit plans
Changes in Accounting Principles**
(40 )
Other
December 31, 2019
$
(46,405 )
(5,357 )
*Cumulative effect of the adoption of ASC Topic 606, "Revenue from Contracts with Customers," and ASU No. 2016-01, "Recognition and
**See Note 2—Changes in Accou nting Principles for additional information.
73
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1—Accounting Policies
■
Consolidation Principles and Investments
—Our consolidated financial statements include the accounts
of majority-owned, controlled subsidiaries and variable interest entities where we are the primary
beneficiary. The equity method is used to account for investments in affiliates in which we have the
ability to exert significant influence over the affiliates’ operating and financial policies. When we do not
have the ability to exert significant influence, the investment is measured at fair value except when the
investment does not have a readily determinable fair value. For those exceptions, it will be measured at
cost minus impairment, plus or minus observable price changes in orderly transactions for an identical or
similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines, natural
gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are
generally carried at cost.
We manage our operations through six operating segments, defined by geographic region: Alaska; Lower
48; Canada; Europe, Middle East and North Africa; Asia Pacific and Other International. For additional
information, see Note 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.
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.
74
■
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
75
exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance
sheet for several years while we perform additional appraisal drilling and seismic work on the
potential oil and gas field or while we seek government or co-venturer approval of development plans
or seek environmental permitting. Once all required approvals and permits have been obtained, the
projects are moved into the development phase, and the oil and gas resources are designated as proved
reserves.
Management reviews suspended well balances quarterly, continuously monitors the results of the
additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes
when it judges the potential field does not warrant further investment in the near term. See Note 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
76
probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be
included in the impairment calculation.
■
Impairment of Investments in Nonconsolidated Entities
—Investments in nonconsolidated entities are
assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has
occurred 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
77
the award was granted with ratable or cliff vesting.
■
Income Taxes
—Deferred income taxes are computed using the liability method and are provided on all
temporary differences between the financial reporting basis and the tax basis of our assets and liabilities,
except for deferred taxes on income and temporary differences related to the cumulative translation
adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate
joint ventures. Allowable tax credits are applied currently as reductions of the provision for income
taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties
related to unrecognized tax benefits are reflected in production and operating expenses.
■
Taxes Collected from Customers and Remitted to Governmental Authorities
—Sales and value-
added taxes are recorded net.
■
Net Income (Loss) Per Share of Common Stock
—Basic net income (loss) per share of common stock
is calculated based upon the daily weighted-average number of common shares outstanding during the
year. Also, this
calculation includes fully vested stock and unit awards that have not yet been issued as
common stock, along with an adjustment to net income (loss) for dividend equivalents paid on unvested
unit awards that are considered participating securities. Diluted net income per share of common stock
includes unvested stock, unit or option awards granted under our compensation plans and vested but
unexercised stock options, but only to the extent these instruments dilute net income per share, primarily
under the treasury-stock method. Diluted net loss per share, which is calculated the same as basic net loss
per share, does not assume conversion or exercise of securities that would have an antidilutive effect.
Treasury stock is excluded from the daily weighted-average number of common shares outstanding in
both calculations. The earnings per share impact of the participating securities is immaterial.
Note 2—Changes in Accounting Principles
We
beginning
. 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 $
corresponding right-of-use assets
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.
78
We
Accumulated Other Comprehensive Income,” beginning
. 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
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
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 $
impairment of $
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 $
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
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.
79
Note 4—Inventories
Inventories at December 31 were:
Millions of Dollars
2019
2018
Crude oil and natural gas
$
Materials and supplies
$
Inventories valued on the LIFO basis totaled $
respectively. The estimated excess of current replacement cost over LIFO cost of inventories was
approximately $
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 $
In addition, we will receive a payment of $
development project. These subsidiaries hold our
Field, our
the Greater Poseidon Fields, and our
approximately $
working capital, offset by $
for sale criteria in the fourth quarter, and as of December 31, 2019 we had reclassified $
“Prepaid expenses and other current assets” and $
consolidated balance sheet. The before-tax earnings associated with our Australia-West subsidiaries were
$
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 segment.
In the fourth quarter of 2019, we signed an agreement to sell our interests in the Niobrara shale play for $
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 $
tax for developed properties and exploration expenses of $
undeveloped properties. Our Niobrara interests to be sold have a net carrying value of approximately $
million, which consisted primarily of $
assets met held for sale criteria in the fourth quarter, and as of December 31, 2019, we had reclassified $
million of PP&E to “Prepaid expenses and other current assets” and $
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 $
December 31, 2019 and 2017, respectively. The before-tax earnings associated with our interests in Niobrara
for the year ended December 31, 2018 was $
other specific conditions precedent and is expected to close in the first quarter of 2020. The Niobrara results of
80
operations are reported within our Lower 48 segment.
Assets Sold
In January 2019, we entered into agreements to sell our
LNG Terminal and Golden Pass Pipeline. We also entered into agreements to amend our contractual
obligations for retaining use of the facilities. As a result of entering into these agreements, we recorded a
before-tax impairment of $
of affiliates” line on our consolidated income statement. We completed the sale in the second quarter of 2019.
Results of operations for these assets 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 $
On September 30, 2019, we completed the sale for proceeds of $
before-tax and $
sold indirectly held our exploration and production assets in the U.K. At the time of disposition, the net
carrying value was approximately $
cumulative foreign currency translation adjustments, and $
billion of ARO and negative $
subsidiaries sold were $
and 2017, respectively. Results of operations for the U.K. are reported within our Europe, Middle East and
North Africa segment.
In the second quarter of 2019, we recognized an after-tax gain of $
our
Greater Sunrise Fields were included in our Asia Pacific segment.
In the fourth quarter of 2019, we sold our interests in the Magnolia field and platform for net proceeds of $
million and recognized a before-tax gain of $
of $
our Lower 48 segment.
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 $
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 $
completed the sale of a package of largely undeveloped acreage in the Lower 48 segment for net proceeds of
$
noncash exchange of undeveloped acreage in the Lower 48 segment. The transaction was recorded at fair
value resulting in the recognition of a $
packages of undeveloped acreage in the Lower 48 segment for total net proceeds of $
recognized gains of approximately $
On October 31, 2018, we completed the sale of our interests in the Barnett to Lime Rock Resources for $
million after customary adjustments and recognized a loss of $
million in 2018 and $
time of the disposition, our interest in Barnett had a net carrying value of $
million of PP&E and $
81
including both the impairments and loss on disposition noted above, were $
years 2018 and 2017, respectively. The Barnett results of operations are included in our Lower 48 segment.
On December 18, 2018, we completed the sale of a ConocoPhillips subsidiary to BP. The subsidiary held
interest in the field. At the same time, we acquired BP’s 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 $
customary adjustments which resulted in net proceeds of $
Field had a net carrying value of approximately $
PP&E, $
$
Field, including the recognized gain, were $
Clair Field was $
within our Europe, Middle East 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
North Slope of Alaska, as well as its interest in the Alpine Transportation Pipeline for $
customary adjustments. This transaction was accounted for as a business combination resulting in the
recognition of approximately $
PP&E, $
included in our Alaska segment.
As discussed in the Clair Field transaction with BP above, we acquired BP’s Kuparuk Assets on December 18,
2018. The transaction was accounted for as an asset acquisition with a net acquisition cost of $
comprised of the fair value of $
interest in the Clair Field, reduced by the net proceeds of $253 million. Accordingly, we recorded
approximately $
investments, $
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 $
Energy common shares and a five-year uncapped contingent payment. The value of the shares at closing was
$
on dispositions” on our consolidated income statement. We reported before-tax equity earnings associated
with FCCL of $
producing properties for 2017. We recorded gains on dispositions for these contingent payments of $
million and $
At closing, the carrying value of our equity investment in FCCL was $
interest in the western Canada gas assets was $
offset by AROs of $
of $
Both FCCL and the western Canada gas assets were reported in our Canada segment.
82
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
Company for $
$
payments of $
recorded an impairment of $
fair value. At the time of disposition, the San Juan Basin interests had a net carrying value of approximately
$
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 $
in our Lower 48 segment.
In September 2017, we completed the sale of our interest in the Panhandle assets for $
customary adjustments and recognized a loss on disposition of $
carrying value of our interest was $
of AROs. Including the $28 million loss on disposition noted above, we reported a before-tax loss for the
Panhandle properties of $
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
$
Loans and advances—related parties
Long-term receivables
Long-term investments in debt securities
Other investments
$
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2019, included:
●
APLNG—
(
process and export LNG.
●
Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned joint venture with affiliates of
Qatar Petroleum (
gas from Qatar’s North Field, as well as exports LNG.
83
Summarized 100 percent earnings information for equity method investments in affiliated companies,
combined, was as follows:
Millions of Dollars
2019
2018
2017
Revenues
$
Income (loss) before income taxes
(2,875 )
Net income (loss)
(1,431 )
Summarized 100 percent balance sheet information for equity method investments in affiliated companies,
combined, was as follows:
Millions of Dollars
2019
2018
Current assets
$
Noncurrent assets
Current liabilities
Noncurrent liabilities
Our share of income taxes incurred directly by an equity method investee is reported in equity in earnings of
affiliates, and as such is not included in income taxes on our consolidated financial statements.
At December 31, 2019, retained earnings included $
affiliated companies. Dividends received from affiliates were $
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 $
billion project finance facility was initially composed of financing agreements executed by APLNG with the
Export-Import Bank of the United States for approximately $
approximately $
approximately $
made its first principal and interest repayment in March 2017 and is scheduled to make
until March 2029.
APLNG made a voluntary repayment of $
At the same time, APLNG obtained a United States Private Placement (USPP) bond facility of $
APLNG made its first interest payment related to this facility in March 2019, and principal payments are
scheduled to commence in September 2023, with
During the first quarter of 2019, APLNG refinanced $
transactions. As a result of the first transaction, APLNG obtained a commercial bank facility of $
APLNG made its first principal and interest repayment in September 2019 with
facility until March 2028. Through the second transaction, APLNG obtained a USPP bond facility of $
billion. APLNG made its first interest payment in September 2019, and principal payments are scheduled to
84
commence in September 2023, with
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 $
and international commercial banks and the Export-Import Bank of China, respectively.
At December 31, 2019, a balance of $
for additional information.
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 $
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 $
The historical cost basis of our
resulting in a basis difference of $
associated with PP&E and subject to amortization, has been allocated on a relative fair value basis to
individual exploration and production license areas owned by APLNG, some of which are not currently in
production. Any future additional payments are expected to be allocated in a similar manner. Each
exploration license area will periodically be reviewed for any indicators of potential impairment, which, if
required, would result in acceleration of basis difference amortization. As the joint venture produces natural
gas from each license, we amortize the basis difference allocated to that license using the unit-of-production
method. Included in net income (loss) attributable to ConocoPhillips for 2019, 2018 and 2017 was after-tax
expense of $
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 $
Term Receivables.” At December 31, 2019, the book value of our equity method investment in QG3,
excluding the project financing, was $
Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with
terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. We
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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.
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
participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of
$
billion from commercial banks, and $
substantially the same terms as the ECA and commercial bank facilities. On December 15, 2011, QG3
achieved financial completion and all project loan facilities became nonrecourse to the project participants.
The long-term portion of these loans is included in the “Loans and advances—related parties” line on our
consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”
Note 7—Investment in Cenovus Energy
On May 17, 2017, we completed the sale of our
well as the majority of our western Canada gas assets, to Cenovus Energy. Consideration for the transaction
included
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 $
the closing date.
Our investment on our consolidated balance sheet as of December 31, 2019, is carried at fair value of $
billion, reflecting the closing price of Cenovus Energy shares on the NYSE of $
$
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.
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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
$
Additions pending the determination of proved reserves
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
$
*
*Includes $
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
$
Exploratory well costs capitalized for a period greater than one year
Ending balance
$
*
Number of projects with exploratory well costs capitalized for a
period greater than one year
*Includes $
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)
NPRA—Alaska
(1)
Barossa/Caldita—Australia
(2)(3)
Surmont—Canada
(1)
Middle Magdalena Basin—Colombia
(1)
Narwhal Trend—Alaska
(1)
Kamunsu East—Malaysia
(2)
NC 98—Libya
(2)
WL4-00—Malaysia
(2)
Other of $10 million or less each
(1)(2)
Total
$
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
(3)Assets held for sale as of December 31, 2019.
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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 $
“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 $
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
$
Lower 48
Canada
Europe, Middle East and North Africa
(79 )
Asia Pacific
$
2019
In the Lower 48, we recorded impairments of $
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 $
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 $
In the Lower 48, we recorded impairments of $
Barnett asset which were written down to fair value less costs to sell, partly offset by a revision to reflect
finalized proceeds on a separate transaction.
In our Europe, Middle East and North Africa segment, we recorded a credit to impairment of $
primarily due to decreased ARO estimates on fields in the U.K. which 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.
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2017
In Alaska, we recorded impairments of $
small interest in the Point Thomson unit.
In the Lower 48, we recorded impairments of $
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 $
In Europe, Middle East and North Africa, we recorded impairments of $
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, we recorded impairments of $
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 $
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 $
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
$
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
Asset retirement obligations and accrued environmental costs due within one year*
(1,025 )
(398 )
Long-term asset retirement obligations and accrued environmental costs
$
*Classified as a current liability on the balance sheet under “Other accruals.” $
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.
89
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
$
Accretion of discount
New obligations
Changes in estimates of existing obligations
(266 )
Spending on existing obligations
(229 )
(228 )
Property dispositions
(1,920 )
(161 )
Foreign currency translation
(80 )
(240 )
Balance at December 31
$
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2019 and 2018, were $
respectively.
We had accrued environmental costs of $
respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and
Other $
December 31, 2019 and 2018, respectively. In addition, $
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
Expected expenditures for environmental obligations acquired in various business combinations are discounted
using a weighted-average
liabilities of $
portion of the accrued environmental costs that have been discounted are: $
2021, $
after 2024.
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Note 11—Debt
Long-term debt at December 31 was:
Millions of Dollars
2019
2018
9.125% Debentures due 2021
$
8.20% Debentures due 2025
8.125% Notes due 2030
7.9% Debentures due 2047
7.8% Debentures due 2027
7.65% Debentures due 2023
7.40% Notes due 2031
7.375% Debentures due 2029
7.25% Notes due 2031
7.20% Notes due 2031
7% Debentures due 2029
6.95% Notes due 2029
6.875% Debentures due 2026
6.50% Notes due 2039
5.951% Notes due 2037
5.95% Notes due 2036
5.95% Notes due 2046
5.90% Notes due 2032
5.90% Notes due 2038
4.95% Notes due 2026
4.30% Notes due 2044
4.15% Notes due 2034
3.35% Notes due 2024
3.35% Notes due 2025
2.4% Notes due 2022
Floating rate notes due 2022 at
% –
% during 2019 and
% –
% during 2018
Industrial Development Bonds due 2035 at
% –
% during 2019 and
% –
% during 2018
Marine Terminal Revenue Refunding Bonds due 2031 at
% –
% during
% –
% during 2018
Other
Debt at face value
Finance leases
Net unamortized premiums, discounts and debt issuance costs
Total debt
Short-term debt
(105 )
(112 )
Long-term debt
$
91
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2020 through
2024 are: $
We have a revolving credit facility totaling $
credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $
million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated
among financial institutions and does not contain any material adverse change provisions or any covenants
requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-
default provision relating to the failure to pay principal or interest on other debt obligations of $
more by ConocoPhillips, or any of its consolidated subsidiaries.
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 $
capital needs. Commercial paper maturities are generally limited to
. We had no commercial paper
outstanding in programs in place at December 31, 2019 or
December 31, 2018
. We had
borrowings or letters of credit under the revolving credit facility at December 31, 2019 or
December 31, 2018
.
Since we had
$
.
At both December 31, 2019 and
2018
, we had $
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
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
. Our maximum exposure under this guarantee is approximately $
and may become payable if an enforcement action is commenced by the project finance lenders
against APLNG. At December 31, 2019, the carrying value of this guarantee is approximately $
million.
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●
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
. Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated to be $
billion in the event of intentional or reckless breach) and would become payable if APLNG fails to
meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future
payments are considered unlikely, as the payments, or cost of volume delivery, would only be
triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-
venturers do not make necessary equity contributions into APLNG.
●
We have guaranteed the performance of APLNG with regard to certain other contracts executed in
connection with the project’s continued development. The guarantees have remaining terms of up to
. 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 $
would become payable if APLNG does not perform.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately
$
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
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 $
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 $
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 $
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.
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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
94
sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have
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
$
supplies, commercial activities and services incident to the ordinary conduct of business.
In 2007, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated
by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company,
Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’
interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In
response to this expropriation, ConocoPhillips initiated international arbitration on November 2, 2007, with the
ICSID. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated
ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the
decision that the expropriation was unlawful. In March 2019, the Tribunal unanimously ordered the
government of Venezuela to pay ConocoPhillips approximately $
government’s unlawful expropriation of the company’s investments in Venezuela in 2007. ConocoPhillips has
filed a request for recognition of the award in several jurisdictions. On August 29, 2019, the ICSID Tribunal
issued a decision rectifying the award and reducing it by approximately $
at $
In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against
PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued
an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $
approximately $
jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices
95
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
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 $
recognition and enforcement of the award in various jurisdictions. ConocoPhillips has ensured that all the
actions related to the award meet all appropriate U.S. regulatory requirements, including those related to any
applicable sanctions imposed by the U.S. against Venezuela.
In February 2017, the ICSID Tribunal unanimously awarded Burlington Resources, Inc., a wholly owned
subsidiary of ConocoPhillips, $
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 $
counterclaims. In December 2017, Burlington and Ecuador entered into a settlement agreement by which
Ecuador paid Burlington $
December 2017, and the second installment of $
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 $
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.
96
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—$
after—$
$
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
$
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our
consolidated income statement were:
Millions of Dollars
2019
2018
2017
Sales and other operating revenues
$
Other income
Purchased commodities
(118 )
(41 )
(61 )
97
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
$
Liabilities
Other accruals
Other liabilities and deferred credits
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
$
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
Sell British pound, buy other currencies*
GBP
Buy British pound, sell euro
GBP
Sell Canadian dollar, buy U.S. dollar
CAD
*Primarily euro and Norwegian krone.
98
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
$
Demand Deposits
Time Deposits
Remaining maturities from 1 to 90 days
Remaining maturities from 91 to 180 days
Commercial Paper
Remaining maturities from 1 to 90 days
U.S. Government Obligations
Remaining maturities from 1 to 90 days
$
99
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
$
Remaining maturities greater than one year through five years
Commercial Paper
Remaining maturities within one year
U.S. Government Obligations
Remaining maturities within one year
Remaining maturities greater than one year through five years
Asset-backed Securities
Remaining maturities greater than one year through five years
$
The following table summarizes the amortized cost basis and fair value of investments in debt securities
classified as available for sale at December 31, 2019:
Millions of Dollars
Amortized Cost
Basis
Fair Value
Major Security Type
Corporate bonds
$
Commercial paper
U.S. government obligations
Asset-backed securities
$
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.
100
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.
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 $
respectively. For these instruments,
December 31, 2018
.
If our credit rating had been downgraded below investment grade on December 31, 2019, we would be
required to post $
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
101
no material transfers in or out of Level 1 during 2019 or 2018.
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
$
Investments in debt securities
Commodity derivatives
Total assets
$
Liabilities
Commodity derivatives
$
Total liabilities
$
102
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
$
Liabilities
December 31, 2018
Assets
$
Liabilities
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)
$
Equity Method Investments
Year ended December 31, 2018
Net PP&E (held for sale)
$
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
103
Topic 323. During 2019, investments using Level 1 inputs were written down to fair value, less costs to sell,
determined by negotiated selling prices. For additional information, see Note 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
$
Commodity derivatives
Investments in debt securities
Total loans and advances—related parties
Financial liabilities
Total debt, excluding finance leases
Commodity derivatives
Commodity Derivatives
At December 31, 2019, commodity derivative assets and liabilities are presented net with $
obligations to return cash collateral and $
December 31, 2018, commodity derivative assets and liabilities are presented net with
cash collateral and $
104
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
Distributed under benefit plans
End of year
Held in Treasury
Beginning of year
Repurchase of common stock
End of year
Preferred Stock
We have authorized
or outstanding at December 31, 2019 or 2018.
Noncontrolling Interests
At December 31, 2019 and 2018, we had $
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 $
stock. Repurchase of shares began in November 2016, and totaled
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 $
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.
105
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
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, $
million of finance lease assets (net of accumulated DD&A) and $
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 $
million of operating leases executed by investee companies accounted for under the proportionate
106
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
$
Accumulated depreciation, depletion and amortization
(550 )
Net properties, plants and equipment as of December 31, 2018
$
Adoption of ASC Topic 842 as of January 1, 2019
$
Lease Liabilities
Short-term debt
$
Long-term debt
Total finance leases debt as of December 31, 2018
$
Adoption of ASC Topic 842 as of January 1, 2019
$
Amounts recognized in line items in our Consolidated
Balance Sheet at December 31, 2019
Right-of-Use Assets
Properties, plants and equipment
Gross
$
Accumulated depreciation, depletion and amortization
(649 )
Net properties, plants and equipment
*
$
Prepaid expenses and other current assets
$
Other assets
* Includes proportionately consolidated finance lease assets (net of accumulated depreciation, depletion and amortization) of $
107
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
Lease Liabilities
Short-term debt
*
$
Other accruals
$
Long-term debt
*
Other liabilities and deferred credits
Total lease liabilities
$
$
720
Short-term debt
long-term debt
The following table summarizes our lease costs for 2019:
Millions of Dollars
2019
Lease Cost
*
Operating lease cost
$
Finance lease cost
Amortization of right-of-use assets
Interest on lease liabilities
Short-term lease cost
**
Total lease cost
***
$
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.
**Short-term leases are not recorded on our consolidated balance sheet. Our future
***Variable lease cost and sublease income are immaterial for the period presented and therefore are not included in the table above
.
108
The following table summarizes the lease terms and discount rates:
December 31, 2019
Lease Term and Discount Rate
Weighted-average term (years)
Operating leases
Finance leases
Weighted-average discount rate (percent)
Operating leases
Finance leases
The following table summarizes other lease information for 2019:
Millions of Dollars
2019
Other Information
*
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases
$
Operating cash flows from finance leases
Financing cash flows from finance leases
Right-of-use assets obtained in exchange for operating lease liabilities
$
Right-of-use assets obtained in exchange for finance lease liabilities
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers. In
addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its intended use
are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.
The following table summarizes future lease payments for operating and finance leases at December 31, 2019:
Millions of Dollars
Operating
Leases
Finance
Maturity of Lease Liabilities
2020
$
2021
2022
2023
2024
Remaining years
Total
*
Less: portion representing imputed interest
(87 )
(160 )
Total lease liabilities
$
*Future lease payments for operating and finance leases commencing on or after January 1, 2019, also include payments related to non -lease
components in accordance with our election to adopt the optional practical expedient not to separate lease components apart from non-lease
components for accounting purposes. In addition, future payments related to operating and finance leases proportionately consolidated by the
company have been included in the table on a proportionate basis consistent with our respective ownership interest in the underlying investee
company or oil and gas venture.
109
At December 31, 2018, future minimum payments due under finance (capital) leases pursuant to
ASC Topic 840 were:
Millions
of Dollars
2019
$
2020
2021
2022
2023
Remaining years
Total
Less: portion representing imputed interest
(195 )
Capital lease obligations
$
At December 31, 2018, future undiscounted minimum rental payments due under noncancelable operating
leases pursuant to ASC Topic 840 were:
Millions
of Dollars
2019
$
2020
2021
2022
2023
Remaining years
Total
Less: income from subleases
(7 )
Net minimum operating lease payments
$
For the years ended December 31, operating lease rental expense pursuant to ASC Topic 840 was:
Millions of Dollars
2018
2017
Total rentals
$
Less: sublease rentals
(16 )
(20 )
$
110
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
$
Service cost
Interest cost
Plan participant contributions
Plan amendments
Actuarial (gain) loss
(44 )
(259 )
(10 )
Benefits paid
(253 )
(147 )
(507 )
(143 )
(59 )
(67 )
Curtailment
(69 )
(4 )
(3 )
Settlement
(730 )
Recognition of termination benefits
Foreign currency exchange rate change
(199 )
(1 )
Benefit obligation at December 31*
$
*Accumulated benefit obligation portion of above at
$
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
$
Actual return on plan assets
(112 )
(106 )
Company contributions
Plan participant contributions
Benefits paid
(253 )
(147 )
(507 )
(143 )
(59 )
(67 )
Settlement
(730 )
Foreign currency exchange rate change
(198 )
Fair value of plan assets at December 31
$
Funded Status
$
(728 )
(800 )
(80 )
(216 )
(218 )
111
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
$
Current liabilities
(21 )
(6 )
(59 )
(4 )
(42 )
(44 )
Noncurrent liabilities
(707 )
(333 )
(741 )
(308 )
(174 )
(174 )
Total recognized
$
(728 )
(800 )
(80 )
(216 )
(218 )
Weighted-Average Assumptions Used to
Determine Benefit Obligations at
December 31
Discount rate
%
Rate of compensation increase
Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost for
Years Ended December 31
Discount rate
%
Expected return on plan assets
Rate of compensation increase
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
$
(21 )
Unrecognized prior service cost (credit)
(2 )
(4 )
(183 )
(216 )
112
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 )
(177 )
(27 )
Amortization of actuarial (gain) loss included
in income (loss)*
(2 )
(1 )
Net change during the period
$
(29 )
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
$
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 $
$
and $
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and
the accumulated benefit obligation were $
and were $
113
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
$
Interest cost
Expected return on plan
assets
(74 )
(138 )
(114 )
(155 )
(132 )
(158 )
Amortization of prior
service cost (credit)
(2 )
(5 )
(6 )
(33 )
(35 )
(36 )
Recognized net actuarial
loss (gain)
(2 )
(1 )
(3 )
Settlements
Net periodic benefit cost
$
(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 $
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 $
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
$
a decrease in the discount rate from
offset by a decrease in the pension benefit obligation from curtailment.
In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-
line basis over the average remaining service period of employees expected to receive benefits under the plan.
For net actuarial gains and losses, we amortize
We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans
are contributory and subject to various cost sharing features, with participant and company contributions
adjusted annually; the life insurance plans are noncontributory. The measurement of the U.S. pre-65 retiree
medical accumulated postretirement benefit obligation assumes a health care cost trend rate of
2020 that declines to
. The measurement of the U.S. post-65 retiree medical accumulated
postretirement benefit obligation assumes an ultimate health care cost trend rate of
114
that increases to
. 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
securities,
are publicly traded, therefore minimizing liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets. There have
been no changes in the methodologies used at December 31, 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.
115
●
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
$
benefit obligation covered by the contract. At December 31, 2018, the participating interest in the
annuity contract was valued at $
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 $
decrease in the present value of the contract obligation of $
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.
$
International
Mutual funds
Debt securities
Government
Corporate
Mutual funds
Cash and cash equivalents
Derivatives
Real estate
Total in fair value hierarchy
$
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
-
-
-
-
-
-
Debt securities
Common/collective trusts
-
-
-
-
-
-
Cash and cash equivalents
-
-
-
-
-
-
Real estate
-
-
-
-
-
-
Total**
$
**Excludes the participating interest in the insurance annuity contract with a net asset of $
116
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.
$
International
Mutual funds
Debt securities
Government
Corporate
Mutual funds
Cash and cash equivalents
Time deposits
Derivatives
(17 )
(17 )
Real estate
Total in fair value hierarchy
$
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
-
-
-
-
-
-
Debt securities
Common/collective trusts
-
-
-
-
-
-
Cash and cash equivalents
-
-
-
-
-
-
Real estate
-
-
-
-
-
-
Total**
$
**Excludes the participating interest in the insurance annuity contract with a net asset of $
Level 3 activity was not material for all periods.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement
Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign
plans are dependent upon local laws and tax regulations. In 2020, we expect to contribute approximately $
million to our domestic qualified and nonqualified pension and postretirement benefit plans and $
our international qualified and nonqualified pension and postretirement benefit plans.
117
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
$
2021
2022
2023
2024
2025–2029
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
$
Accruals
(1 )
Benefit payments
(24 )
Balance at December 31, 2019
$
Of the remaining balance at December 31, 2019, $
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can
deposit up to
approximately
their eligible pay receive a
contribution of up to
to opt out of Title II are eligible to receive a CRC of
contributions charged to expense for the CPSP and predecessor plans were $
2018, and $
We have several defined contribution plans for our international employees, each with its own terms and
eligibility depending on location. Total compensation expense recognized for these international plans was
approximately $
Share-Based Compensation Plans
The 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by
shareholders in May 2014. Over its
-year life, the Plan allows the issuance of up to
common stock for compensation to our employees and directors; however, as of the effective date of the Plan,
(i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common
stock represented by awards granted under the prior plans that are forfeited, expire or are cancelled without
delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the
company shall be available for awards under the Plan, and no new awards shall be granted under the prior
plans. Of the 79 million shares available for issuance under the Plan, no more than
common stock are available for incentive stock options. The Human Resources and Compensation Committee
118
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
$
Tax benefit
Stock Options
—
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
%
Dividend yield
%
Volatility factor
%
Expected life (years)
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
119
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
$
$
Exercised
(1,339,480 )
Forfeited
Expired or cancelled
Outstanding at December 31, 2019
$
$
Vested at December 31, 2019
$
$
Exercisable at December 31, 2019
$
$
The weighted-average remaining contractual term of outstanding options, vested options and exercisable
options at December 31, 2019, was
grant date fair value of stock option awards granted during 2017 was $
. The aggregate intrinsic value of
options exercised was $
During 2019, we received $
options. At December 31, 2019, the remaining unrecognized compensation expense from unvested options
was
.
Stock Unit Program—
.
Stock-Settled
.
120
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
$
Granted
Forfeited
(99,748 )
Issued
(3,269,682 )
$
Outstanding at December 31, 2019
$
Not Vested at December 31, 2019
At December 31, 2019, the remaining unrecognized compensation cost from the unvested stock-settled units
was $
being
2017 was $
, respectively. The total fair value of stock units issued during 2018 and 2017 was
$
Cash-Settled
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
$
Granted
Forfeited
(6,914 )
Issued
(92,255 )
$
Outstanding at December 31, 2019
$
Not Vested at December 31, 2019
At December 31, 2019, the remaining unrecognized compensation cost from the unvested cash-settled units
was $
being
$
. The total fair value of stock units issued during 2018 was $
121
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
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
$
Granted
Forfeited
Issued
(388,559 )
$
Outstanding at December 31, 2019
$
Not Vested at December 31, 2019
$
At December 31, 2019, the remaining unrecognized compensation cost from unvested stock-settled
performance share awards was
. The weighted-average grant date fair value of stock-settled PSUs granted
during 2018 and 2017 was $
, respectively. The total fair value of stock-settled PSUs issued
during 2018 and 2017 was $
Cash-Settled
In connection with and immediately following the separation of our Downstream businesses in 2012, grants of
new PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent
employee election to defer, on the earlier of five years after the grant date of the award or the date the
employee becomes eligible for retirement. For employees eligible for retirement by or shortly after the grant
date, we recognize compensation expense over the period beginning on the date of authorization and ending on
the date of grant. Otherwise, we recognize compensation expense beginning on the grant date and ending on
the date the PSUs are scheduled to vest. These PSUs are settled in cash equal to the fair market value of a
share of ConocoPhillips common stock per unit on the settlement date and thus are classified as liabilities on
the balance sheet. Until settlement occurs, recipients of the PSUs receive a quarterly cash payment of a
122
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
$
Granted
Forfeited
Settled
(2,479,776 )
$
Outstanding at December 31, 2019
$
Not Vested at December 31, 2019
$
At December 31, 2019, the remaining unrecognized compensation cost from unvested cash-settled
performance share awards was
. The weighted-average grant date fair value of cash-settled PSUs granted
during 2018 and 2017 was $
, respectively. The total fair value of cash-settled performance
share awards settled during 2018 and 2017 was $
From inception of the Performance Share Program through 2013, approved PSU awards were granted after the
conclusion of performance periods.
Other
—In addition to the above active programs, we have outstanding shares of restricted stock and restricted
stock units that were either issued as part of our non-employee director compensation program for current and
former members of the company’s Board of Directors or as part of an executive compensation program that
has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or
dividend equivalent.
123
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
$
Granted
Cancelled
(2,307 )
Issued
(177,163 )
$
Outstanding at December 31, 2019
$
At December 31, 2019, all outstanding restricted stock and restricted stock units were fully vested and there
was
granted during 2018 and 2017 was $
, respectively. The total fair value of awards issued
during 2018 and 2017 was $
Note 19—Income Taxes
Income taxes charged to net income (loss) were:
Millions of Dollars
2019
2018
2017
Income Taxes
Federal
Current
$
Deferred
(113 )
(3,046 )
Foreign
Current
Deferred
(323 )
(166 )
(510 )
State and local
Current
Deferred
(8 )
(96 )
(125 )
$
(1,822 )
124
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
$
Inventory
Deferred state income tax
Other
Total deferred tax liabilities
Deferred Tax Assets
Benefit plan accruals
Asset retirement obligations and accrued environmental costs
Investments in joint ventures
Other financial accruals and deferrals
Loss and credit carryforwards
Other
Total deferred tax assets
Less: valuation allowance
(10,214 )
(3,040 )
Net deferred tax assets
Net deferred tax liabilities
$
At December 31, 2019, noncurrent assets and liabilities included deferred taxes of $
$
of $
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
$
U.S. general business credits
U.S. capital loss
State net operating losses and tax credits
Foreign net operating losses and tax credits
$
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 $
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.
125
On December 2, 2019, the Internal Revenue Service finalized foreign tax credit regulations related to the 2017
Tax Cuts and Jobs Act. Due to the finalization of these regulations, in the fourth quarter of 2019 we
recognized $
foreign tax credit carryovers where recognition was previously considered to be remote. Present legislation
still makes their realization unlikely and therefore these credits have been offset with a full valuation
allowance.
At December 31, 2019, unremitted income considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures totaled approximately $
have not been provided on this amount, as we do not plan to initiate any action that would require the payment
of income taxes. The estimated amount of additional tax, primarily local withholding tax, that would be
payable on this income if distributed is approximately $
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2019,
2018 and 2017:
Millions of Dollars
2019
2018
2017
Balance at January 1
$
Additions based on tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
(22 )
(73 )
(129 )
Settlements
(9 )
(35 )
(5 )
Lapse of statute
(2 )
(4 )
(86 )
Balance at December 31
$
Included in the balance of unrecognized tax benefits for 2019, 2018 and 2017 were $
$
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 $
$
benefit to earnings of $
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.
126
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
$
(5,250 )
%
Foreign
(100.8 )
$
(2,615 )
%
Federal statutory income tax
$
(915 )
%
Non-U.S. effective tax rates
(23.9 )
Tax Legislation
(10 )
(852 )
(0.1 )
Canada disposition
(1,277 )
U.K. disposition
(732 )
(150 )
(7.7 )
(1.5 )
Recovery of outside basis
(77 )
(21 )
(962 )
(0.8 )
(0.2 )
Adjustment to tax reserves
(4 )
(33.7 )
Adjustment to valuation allowance
(225 )
(26 )
(2.4 )
(0.3 )
APLNG impairment
(31.9 )
State income tax
(84 )
Malaysia Deepwater Incentive
(164 )
(1.7 )
Enhanced oil recovery credit
(27 )
(99 )
(68 )
(0.3 )
(1.0 )
Other
(39 )
(18 )
(4 )
(0.4 )
(0.2 )
$
(1,822 )
%
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 $
million. The disposition generated a U.S. capital loss of approximately $
tax benefit of approximately $
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 $
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 $
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.
127
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 $
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 $
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 $
calculations during the 12 months ended December 31, 2018, we adjusted our provisional amount by $
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 $
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 $
believe it is not likely we will receive a corresponding cash tax savings, this $
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 $
128
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)
(58 )
December 31, 2017
(400 )
(58 )
(5,060 )
(5,518 )
Other comprehensive income (loss)
-
(642 )
(603 )
Cumulative effect of adopting ASU No. 2016-01*
-
-
December 31, 2018
(361 )
(5,702 )
(6,063 )
Other comprehensive income
-
Cumulative effect of adopting ASU No. 2018-02**
(40 )
-
-
(40 )
December 31, 2019
$
(350 )
(5,007 )
(5,357 )
*We adopted ASU No. 2016-01, "Recognition and Measurement of Financial Assets and Liabilities," beginning January 1, 2018.
—
Changes in Accounting Principles for additional information.
During 2019, we recognized $
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
$
Above amounts are included in the computation of net periodic benefit cost and
are presented net of tax expense of:
$
See Note 18—Employee Benefit Plans, for additional information.
129
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
$
(37 )
Increase (decrease) in assets and liabilities acquired in a nonmonetary
exchange*
Accounts receivable
(44 )
Inventories
Investments and long-term receivables
PP&E
Other long-term assets
(9 )
Accounts payable
Accrued income and other taxes
Cash Payments
Interest
$
Income taxes
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(4,902 )
(1,953 )
(6,617 )
Short-term investments sold
Investments and long-term receivables purchased
(146 )
$
(2,910 )
(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 $
agreement related to an award issued by the ICC Tribunal in 2018. We collected $
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 $
our domestic qualified pension plan of $
In 2017, we recognized a $
transactions.
130
Note 22—Other Financial Information
Millions of Dollars
2019
2018
2017
Interest and Debt Expense
Incurred
Debt
$
Other
Capitalized
(57 )
(170 )
(119 )
Expensed
$
Other Income
Interest income
$
Unrealized gains (losses) on Cenovus Energy common shares*
(437 )
Other, net
$
*See Note 7—Investment in Cenovus Energy, for additional information.
Research and Development Expenditures
—expensed
$
Shipping and Handling Costs
$
Foreign Currency Transaction (Gains) Losses
—after-tax
Alaska
$
Lower 48
Canada
(11 )
Europe, Middle East and North Africa
(26 )
Asia Pacific
Other International
Corporate and Other
(3 )
$
(13 )
Millions of Dollars
2019
2018
Properties, Plants and Equipment
Proved properties
$
*
Unproved properties
*
Other
Gross properties, plants and equipment
Less: Accumulated depreciation, depletion and amortization
(55,477)
*
(64,899)
Net properties, plants and equipment
$
*Excludes assets classified as held for sale at December 31, 2019. See Note 5
—
Asset Acquisitions and Dispositions, for additional information.
131
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
$
Purchases
Operating expenses and selling, general and administrative expenses
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
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
$
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative
Financial derivative contracts
(97 )
(88 )
Consolidated sales and other operating revenues
$
Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at
market prices which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,”
and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy
for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following
disaggregation of revenues is provided in conjunction with Note 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
$
Canada
Europe, Middle East and North Africa
Physical contracts meeting the definition of a derivative
$
132
Millions of Dollars
2019
2018
2017
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
Natural gas
Other
Physical contracts meeting the definition of a derivative
$
Practical Expedients
Typically, our commodity sales contracts are less than 12 months in duration; however, in certain specific
cases may extend longer, which may be out to the end of field life.
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 $
contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC
Topic 606.
contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative
under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade
receivables associated with gas sold under contracts for which NPNS has not been elected compared with trade
receivables where NPNS has been elected.
Contract Liabilities from Contracts with Customers
Millions of
Dollars
Contract Liabilities
At December 31, 2018
$
Contractual payments received
Revenue recognized
(199 )
At December 31, 2019
$
133
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
region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific 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.
Effective with the third quarter of 2020, we have restructured our segments to align with the changes to our
internal organization. The Middle East business was realigned from the Asia Pacific and Middle East segment
to the Europe and North Africa segment. The segments have been renamed the Asia Pacific segment and the
Europe, Middle East and North Africa segment. We have revised segment information disclosures and
segment performance metrics presented within our results of operations for the current and prior years.
Analysis of Results by Operating Segment
Millions of Dollars
2019
**
2018
**
2017
**
Sales and Other Operating Revenues
Alaska
$
Lower 48
Intersegment eliminations
(46 )
(40 )
(4 )
Lower 48
Canada
Intersegment eliminations
(1,141 )
(1,160 )
(559 )
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated sales and other operating revenues
$
Depreciation, Depletion, Amortization and Impairments
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated depreciation, depletion, amortization and impairments
$
The market for our products is large and diverse, therefore, our sales and other operating revenues are not
dependent upon any single customer.
134
Millions of Dollars
2019
**
2018
**
2017
**
Equity in Earnings of Affiliates
Alaska
$
Lower 48
(159 )
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated equity in earnings of affiliates
$
Income Taxes
Alaska
$
(689 )
Lower 48
(2,453 )
Canada
(43 )
(96 )
(616 )
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
(233 )
(103 )
Consolidated income taxes
$
(1,822 )
Net Income (Loss) Attributable to ConocoPhillips
Alaska
$
Lower 48
(2,371 )
Canada
Europe, Middle East and North Africa
Asia Pacific
(1,661 )
Other International
Corporate and Other
(1,667 )
(2,136 )
Consolidated net income (loss) attributable to ConocoPhillips
$
(855 )
Investments in and Advances to Affiliates
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated investments in and advances to affiliates
$
135
Millions of Dollars
2019
**
2018
**
2017
**
Total Assets
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated total assets
$
Capital Expenditures and Investments
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated capital expenditures and investments
$
Interest Income and Expense
Interest income
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Interest and debt expense
Corporate and Other
$
Sales and Other Operating Revenues by Product
Crude oil
$
Natural gas
Natural gas liquids
Other*
Consolidated sales and other operating revenues by product
$
*Includes LNG and bitumen.
**Prior periods have been updated to reflect the Middle East Business Unit moving from Asia Pacific to the Europe, Middle East and North
Africa segment.
136
Geographic Information
Millions of Dollars
Sales and Other Operating Revenues
(1)
Long-Lived Assets
(2)
2019
2018
2017
2019
2018
2017
United States
(3)
$
Australia and Timor-Leste
(4)
Canada
China
Indonesia
Libya
Malaysia
Norway
United Kingdom
Other foreign countries
Worldwide consolidated
$
(1)
Sales and other operating revenues are attributable to countries based on the location of the selling operation.
(2)
Defined as net PP&E plus equity investments and advances to affiliated companies.
(3)
Long-lived assets do not include $
2019. See Note 5—Acquisitions and Dispositions, for additional information.
(4)
Long-lived assets do not include $
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.
137
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
138
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 99.2 of this Current
Report on Form 8-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.
139
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
140
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:
141
●
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.
142
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
143
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.
144
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
145
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.
146
●
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.
147
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
148
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.
149
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
150
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.
151
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.
152
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
153
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
154
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)
155
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
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
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
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.
156
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
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
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
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 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 Operation s.
157
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
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
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
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.
158
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
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
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.
159
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
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
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
160
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
161
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
162
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
163
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
164
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.
165
Selected Quarterly Financial Data
(Unaudited)
Millions of Dollars
Per Share of Common Stock
Sales and
Net Income
Net Income (Loss)
Income (Loss)
Net
(Loss)
Attributable
Operating
Before
Income
Attributable to
to ConocoPhillips
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.
166
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 $
from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had
no impact on our consolidated financial statements.
In 2017, ConocoPhillips received a $
ConocoPhillips Company to settle certain accumulated intercompany balances. These transactions had no
impact on our consolidated financial statements.
In 2018, ConocoPhillips Company received a $
from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had
no impact on our consolidated financial statements.
In 2018, ConocoPhillips received a $
ConocoPhillips Company to settle certain accumulated intercompany balances. These transactions had no
impact on our consolidated financial statements.
In 2019, ConocoPhillips received a $
ConocoPhillips Company to settle certain accumulated intercompany balances. This transaction had no impact
on our consolidated financial statements.
In 2019, ConocoPhillips Company received a $
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 $
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.
167
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
$
Equity in earnings of affiliates
(14,306 )
Gain (loss) on dispositions
(820 )
Other income
Intercompany revenues
(5,695 )
Total Revenues and Other Income
(20,001 )
Costs and Expenses
Purchased commodities
(5,034 )
Production and operating expenses
(405 )
Selling, general and administrative expenses
(5 )
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
(251 )
Foreign currency transaction losses
Other expenses
Total Costs and Expenses
(5,695 )
Income before income taxes
(14,306 )
Income tax provision (benefit)
(62 )
(448 )
(46 )
Net income
(14,306 )
Less: net income attributable to noncontrolling interests
(68 )
(68 )
Net Income Attributable to ConocoPhillips
$
(14,306 )
Comprehensive Income Attributable to ConocoPhillips
$
(16,096 )
Income Statement
Year Ended December 31, 2018
Revenues and Other Income
Sales and other operating revenues
$
Equity in earnings of affiliates
(16,596 )
Gain on dispositions
Other income (loss)
(384 )
Intercompany revenues
(5,867 )
Total Revenues and Other Income
(22,463 )
Costs and Expenses
Purchased commodities
(5,428 )
Production and operating expenses
(59 )
Selling, general and administrative expenses
(5 )
Exploration expenses
Depreciation, depletion and amortization
Impairments
(10 )
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
(375 )
Foreign currency transaction (gains) losses
(12 )
(167 )
(17 )
Other expenses
Total Costs and Expenses
(5,867 )
Income before income taxes
(16,596 )
Income tax provision (benefit)
(68 )
(41 )
Net income
(16,596 )
Less: net income attributable to noncontrolling interests
(48 )
(48 )
Net Income Attributable to ConocoPhillips
$
(16,596 )
Comprehensive Income Attributable to ConocoPhillips
$
(15,225 )
See Notes to Consolidated Financial Statements.
168
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
$
Equity in earnings (losses) of affiliates
(454 )
(2,477 )
Gain on dispositions
Other income
Intercompany revenues
(3,721 )
Total Revenues and Other Income
(404 )
(6,198 )
Costs and Expenses
Purchased commodities
(3,250 )
Production and operating expenses
(17 )
Selling, general and administrative expenses
(6 )
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
(448 )
Foreign currency transaction (gains) losses
(43 )
(137 )
Other expenses
(6 )
Total Costs and Expenses
(84 )
(3,721 )
Income (Loss) before income taxes
(1,057 )
(171 )
(2,477 )
(2,615 )
Income tax provision (benefit)
(202 )
(337 )
(1,566 )
(1,822 )
Net income (loss)
(855 )
(454 )
(2,477 )
(793 )
Less: net income attributable to noncontrolling interests
(62 )
(62 )
Net Income (Loss) Attributable to ConocoPhillips
$
(855 )
(454 )
(2,477 )
(855 )
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
(180 )
(4,168 )
(180 )
See Notes to Consolidated Financial Statements.
169
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
$
Short-term investments
Accounts and notes receivable
(2,575 )
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
(2,575 )
Investments, loans and long-term receivables*
(97,413 )
Net properties, plants and equipment
Other assets
(805 )
Total Assets
$
(100,793 )
Liabilities and Stockholders’ Equity
Accounts payable
$
(2,575 )
Short-term debt
(3 )
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
(2,575 )
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
(804 )
Employee benefit obligations
Other liabilities and deferred credits*
(17,534 )
Total Liabilities
(20,913 )
Retained earnings
(27,985 )
Other common stockholders’ equity
(4,761 )
(51,895 )
(4,761 )
Noncontrolling interests
Total Liabilities and Stockholders’ Equity
$
(100,793 )
Balance Sheet
At December 31, 2018
Assets
Cash and cash equivalents
$
Short-term investments
Accounts and notes receivable
(8,392 )
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
(8,392 )
Investments, loans and long-term receivables*
(99,465 )
Net properties, plants and equipment
(465 )
Other assets
(798 )
Total Assets
$
(109,120 )
Liabilities and Stockholders’ Equity
Accounts payable
$
(8,392 )
Short-term debt
(3 )
(9 )
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
(8,401 )
Long-term debt
(478 )
Asset retirement obligations and accrued environmental costs
Deferred income taxes
(798 )
Employee benefit obligations
Other liabilities and deferred credits*
(17,775 )
Total Liabilities
(27,452 )
Retained earnings
(22,890 )
Other common stockholders’ equity
(2,135 )
(58,778 )
(2,071 )
Noncontrolling interests
Total Liabilities and Stockholders’ Equity
$
(109,120 )
*Includes intercompany loans.
See Notes to Consolidated Financial Statements.
170
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
$
(11,349 )
Cash Flows From Investing Activities
Capital expenditures and investments
(2,517 )
(5,714 )
(6,636 )
Working capital changes associated with investing activities
(140 )
(103 )
Proceeds from asset dispositions
(8,233 )
Net purchases of investments
(2,803 )
(107 )
(2,910 )
Long-term advances/loans—related parties
(812 )
Collection of advances/loans—related parties
(161 )
Intercompany cash management
(2,849 )
Other
(149 )
(108 )
Net Cash Provided by (Used in) Investing Activities
(1,905 )
(4,331 )
(5,987 )
(6,618 )
Cash Flows From Financing Activities
Issuance of debt
(812 )
Repayment of debt
(21 )
(220 )
(80 )
Issuance of company common stock
(135 )
(30 )
Repurchase of company common stock
(3,500 )
(3,500 )
Dividends paid
(1,500 )
(4,034 )
(454 )
(7,097 )
(1,500 )
Other
(4,924 )
(1,736 )
(119 )
Net Cash Used in Financing Activities
(4,891 )
(4,055 )
(5,378 )
(8,241 )
(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
(2,804 )
(789 )
Cash, cash equivalents and restricted cash at beginning of period
Cash, Cash Equivalents and Restricted Cash at End of Period
$
Statement of Cash Flows
Year Ended December 31, 2018*
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
$
(6,915 )
Cash Flows From Investing Activities
Capital expenditures and investments
(980 )
(603 )
(5,777 )
(6,750 )
Working capital changes associated with investing activities
(110 )
(68 )
Proceeds from asset dispositions
(5,672 )
Net sales of short-term investments
Long-term advances/loans—related parties
(126 )
(173 )
(10 )
Collection of advances/loans—related parties
(4,243 )
Intercompany cash management
(803 )
(2,150 )
(551 )
Other
Net Cash Provided by (Used in) Investing Activities
(788 )
(3,839 )
(8,996 )
(3,843 )
Cash Flows From Financing Activities
Issuance of debt
(309 )
Repayment of debt
(4,865 )
(53 )
(4,320 )
(4,995 )
Issuance of company common stock
(133 )
Repurchase of company common stock
(2,999 )
(2,999 )
Dividends paid
(1,363 )
(1,043 )
(6,057 )
(1,363 )
Other
(3,468 )
(1,670 )
(123 )
Net Cash Used in Financing Activities
(4,103 )
(9,366 )
(53 )
(11,748 )
(9,359 )
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
(121 )
(117 )
Net Change in Cash, Cash Equivalents and Restricted Cash
(3 )
(1,576 )
(385 )
Cash, cash equivalents and restricted cash at beginning of period
Cash, Cash Equivalents and Restricted Cash at End of Period
$
*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.
171
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
$
(3,052 )
Cash Flows From Investing Activities
Capital expenditures and investments
(1,663 )
(4,351 )
(3,795 )
(4,591 )
Working capital changes associated with investing activities
(62 )
Proceeds from asset dispositions
(30,025 )
Net purchases of short-term investments
(1,790 )
(1,790 )
Long-term advances/loans—related parties
(214 )
(65 )
(20 )
Collection of advances/loans—related parties
(4,655 )
Intercompany cash management
(1,341 )
Other
(8 )
Net Cash Provided by Investing Activities
(29,163 )
Cash Flows From Financing Activities
Issuance of debt
(299 )
Repayment of debt
(5,459 )
(4,411 )
(2,661 )
(7,876 )
Issuance of company common stock
(178 )
(63 )
Repurchase of company common stock
(3,000 )
(3,000 )
Dividends paid
(1,305 )
(235 )
(2,995 )
(1,305 )
Other
(7,765 )
(9,781 )
(7,377 )
(112 )
Net Cash Used in Financing Activities
(9,645 )
(12,391 )
(9,781 )
(12,754 )
(12,356 )
Effect of Exchange Rate Changes on Cash and Cash Equivalents
(2 )
Net Change in Cash and Cash Equivalents
(124 )
(2 )
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
$
See Notes to Consolidated Financial Statements.
172
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 62, are filed as part of this Current Report.
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.
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
$
(17 )
(b)
Deferred tax asset valuation allowance
(26 )
(176 )
Included in other liabilities:
Restructuring accruals
(1 )
(24 )
(c)
2018
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
(2 )
(b)
Deferred tax asset valuation allowance
(8 )
(273 )
Included in other liabilities:
Restructuring accruals
(2 )
(73 )
(c)
2017
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
(3 )
(b)
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
(93 )
(c)
(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.
Exhibit 99.2
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
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.
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