Curtis Island on Australia’s east coast is home to Australia Pacific LNG, which produces liquefied natural gas for the global market. Demand is rising worldwide for this abundant, affordable and clean-burning energy source.ConocoPhillips 2019 ANNUAL REPORT2019ANNUAL REPORT Dear Fellow Shareholders: I’m pleased to report that 2019 was another successful year for ConocoPhillips, capping off a three-year period during which we transformed our business model and significantly improved the underlying performance drivers across our entire business. In late 2016 we launched a “new-order” business model for the upstream energy sector that focused on a disciplined strategy framework, consistent execution, a strong balance sheet, free cash flow generation, compelling returns of and returns on capital, and a clear commitment to environmental, social and governance leadership. We believed then — and believe now — that this approach positions ConocoPhillips to deliver sustained value through our sector’s inevitable price cycles. Since that 2016 reset we’ve successfully executed this strategy, and our 2019 results built upon this multi-year track record.Our financial achievements during 2019 included generating cash from operations of $11.7 billion, with free cash flow of over $5 billion. We strengthened our balance sheet, ending the year with more than $8 billion in cash and short-term investments. We lowered our asset retirement obligations by almost 30 percent, largely through asset dispositions. Importantly, we achieved an 11 percent return on capital employed, which we consider our North Star.We delivered on our volume projections for the year, achieving 5 percent growth in underlying production, including 22 percent growth on a combined basis from the Lower 48 Big 3 unconventional fields — Eagle Ford, Bakken and Permian. The rest of our portfolio delivered strong base performance, and we progressed new projects and exploration opportunities across our regions.We improved our world-class asset portfolio through high-grading. We generated $3 billion of disposition proceeds, with another $2 billion of announced dispositions expected to close in early 2020. We also added low cost of supply resources to the portfolio, which allowed us to exit the year with resources of about 15 billion barrels of oil equivalent in our investment inventory with a cost of supply less than $40 per barrel. As for reserves, in 2019 we replaced 100 percent of our production and, excluding dispositions, replaced 117 percent of our production organically.It was an outstanding year for delivery of our disciplined, shareholder-friendly strategy. We returned 43 percent of cash from operations to our shareholders, which represented nearly all our free cash flow. We paid $1.5 billion in dividends, including a 38 percent increase in our quarterly dividend, and repurchased $3.5 billion of shares. In January 2020, our board of directors increased our existing share repurchase authorization by $10 billion to a total of $25 billion, demonstrating our commitment to a consistent long-term buyback program.But 2019, like the years before it, was not just about the numbers. We continued taking a leadership role in environmental, social and governance matters through target-setting, stakeholder engagement and alignment, disclosure and advocacy. We call this “performance with purpose,” and consider it imperative for today’s license to operate.As we turn the page and begin a new year and new decade, our industry is off to another volatile start. Volatility can be tough on companies not built for it. But ConocoPhillips is built for it, with clear resilience to lower prices, full upside to higher prices and a shareholder-friendly strategy framework that works throughout the business cycles. In November we laid out a powerful 10-year plan, reaffirming our commitment to the disciplined strategy we set for ourselves in 2016. We delivered on that strategy in 2017, 2018 and 2019, and we’re ready to deliver on it again in 2020. We’re focused on executing a plan that we believe is right for the future of our industry and right for our investors.In recognition of these achievements and goals for the future, our board of directors and leadership team express appreciation to employees for their focus and dedication, and we thank our shareholders for their continued trust. Ryan M. LanceChairman and Chief Executive OfficerFeb. 18, 2020LETTER TO SHAREHOLDERSBOARD OF DIRECTORS(As of Feb. 18, 2020)Charles E. Bunch Former Chairman and Chief Executive Officer, PPG Industries, Inc.Caroline Maury DevineFormer President and Managing Director of a Norwegian affiliate of ExxonMobilJohn V. Faraci Former Chairman and Chief Executive Officer, International Paper CompanyJody Freeman Archibald Cox Professor of Law, Harvard Law SchoolGay Huey Evans OBE Chairman, London Metal ExchangeJeffrey A. Joerres Former Executive Chairman and Chief Executive Officer, ManpowerGroup Inc.Ryan M. Lance Chairman and Chief Executive Officer, ConocoPhillipsRyan M. LanceChairman and Chief Executive OfficerMatt J. FoxExecutive Vice President and Chief Operating OfficerDon E. Wallette, Jr.Executive Vice President and Chief Financial OfficerWilliam L. Bullock, Jr.President, Asia Pacific and Middle EastEllen R. DeSanctisSenior Vice President, Corporate RelationsEXECUTIVE LEADERSHIP TEAM(As of Feb. 18, 2020)Admiral William H. McRavenRetired U.S. Navy Four-Star Admiral (SEAL) Sharmila MulliganChief Strategy Officer, AlteryxArjun N. Murti Senior Advisor, Warburg PincusRobert A. Niblock Former Chairman, President and Chief Executive Officer, Lowe’s Companies, Inc.Elected March 2, 2020David T. SeatonFormer Chairman and Chief Executive Officer, Fluor Corporation R.A. WalkerFormer Chairman and Chief Executive Officer, Anadarko Petroleum CorporationMichael D. HatfieldPresident, Alaska, Canada and EuropeAndrew D. LundquistSenior Vice President, Government AffairsDominic E. MacklonPresident, Lower 48Kelly B. RoseSenior Vice President, Legal, General Counsel and Corporate SecretaryCertain disclosures in this annual report may be considered “forward-looking” statements. These are made pursuant to “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The “Cautionary Statement” in the Management’s Discussion and Analysis in ConocoPhillips’ 2019 Form 10-K should be read in conjunction with such statements.“ConocoPhillips,” “the company,” “we,” “us” and “our” are used interchangeably in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries.Cautionary Note to U.S. Investors – The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. We use the terms “resource” and “resources” in this annual report, which the SEC’s guidelines prohibit us from including in filings with the SEC. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC. Copies are available from the SEC and on the ConocoPhillips website.EXPLORE CONOCOPHILLIPSSustainability ReportOur annual Sustainability Report provides details on priority reporting issues for the company, a letter from our CEO and key environmental, social and governance metrics. The report is updated in June and is available on our website at www.conocophillips.com/susdev.Managing Climate-Related Risks ReportOur Managing Climate-Related Risks Report includes a letter from our CEO and details on our governance framework, risk management approach, strategy, and key metrics and targets for climate-related issues. The report is available on our website at www.conocophillips.com/ climatechange.2019 Analyst & Investor MeetingDuring 2019 ConocoPhillips conducted an Analyst & Investor Meeting that presented an overview of the company’s 10-year strategic plan. A slide deck and transcript are available on our website at www.conocophillips.com/ investorpresentations.Fact SheetsThe ConocoPhillips Fact Sheets provide detailed operational updates for each of the company’s six segments. The Fact Sheets are updated annually and are available at www.conocophillips.com/factsheets. 2019
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
OR
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
Delaware
incorporation or organization)
01-0562944
(I.R.S. Employer
Identification No.)
(State or other jurisdiction of
925 N. Eldridge Parkway
Houston, TX 77079
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-293-1000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $.01 Par Value
7% Debentures due 2029
Trading symbols
COP
CUSIP—718507BK1
Name of each exchange on which registered
New York Stock Exchange
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[x] Yes [ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
[ ] Yes [x] No
Act.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be
submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit such files).
[x] Yes [ ] No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a
smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”
“accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [x] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]
Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended
transition period for complying with any new or revised financial accounting standards provided pursuant to Section
13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [ ] Yes [x] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 28, 2019, the last
business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date
of $61.00, was $67.7 billion.
The registrant had 1,081,132,415 shares of common stock outstanding at January 31, 2020.
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2020 (Part III)
Documents incorporated by reference:
TABLE OF CONTENTS
Commonly Used Abbreviations……………………………………………………………………….
Item
PART I
1 and 2. Business and Properties ......................................................................................................
Corporate Structure ........................................................................................................
Segment and Geographic Information ...........................................................................
Alaska .......................................................................................................................
Lower 48 ...................................................................................................................
Canada ......................................................................................................................
Europe and North Africa ...........................................................................................
Asia Pacific and Middle East ....................................................................................
Other International ....................................................................................................
Competition ...................................................................................................................
General ...........................................................................................................................
1A. Risk Factors ........................................................................................................................
1B. Unresolved Staff Comments ...............................................................................................
3. Legal Proceedings ...............................................................................................................
4. Mine Safety Disclosures .....................................................................................................
Information About our Executive Officers .........................................................................
PART II
5. Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities ............................................................................
6. Selected Financial Data ......................................................................................................
7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations .....................................................................................................
7A. Quantitative and Qualitative Disclosures About Market Risk ............................................
8. Financial Statements and Supplementary Data ...................................................................
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.......................................................................................................
9A. Controls and Procedures .....................................................................................................
9B. Other Information ...............................................................................................................
PART III
10. Directors, Executive Officers and Corporate Governance..................................................
11. Executive Compensation ....................................................................................................
12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters ..........................................................................................
13. Certain Relationships and Related Transactions, and Director Independence ...................
14. Principal Accounting Fees and Services .............................................................................
PART IV
Page
1
2
2
2
4
6
9
10
12
17
19
19
21
28
28
28
29
31
34
35
72
75
185
185
185
186
186
186
186
186
15. Exhibits, Financial Statement Schedules ............................................................................
Signatures ...........................................................................................................................
187
197
Commonly Used Abbreviations
The following industry-specific, accounting and other terms, and abbreviations may be commonly used in this
report.
Currencies
$ or USD
CAD
GBP
Units of Measurement
BBL
BCF
BOE
MBD
MCF
MMBOE
MBOED
MMBTU
MMCFD
Industry
CBM
E&P
FEED
FPS
FPSO
JOA
LNG
NGLs
OPEC
PSC
PUDs
SAGD
WCS
WTI
U.S. dollar
Canadian dollar
British pound
barrel
billion cubic feet
barrels of oil equivalent
thousands of barrels per day
thousand cubic feet
million barrels of oil equivalent
thousands of barrels of oil
equivalent per day
million British thermal units
million cubic feet per day
coalbed methane
exploration and production
front-end engineering and design
floating production system
floating production, storage and
offloading
joint operating agreement
liquefied natural gas
natural gas liquids
Organization of Petroleum
Exporting Countries
production sharing contract
proved undeveloped reserves
steam-assisted gravity drainage
Western Canada Select
West Texas Intermediate
Accounting
ARO
ASC
ASU
DD&A
FASB
FIFO
G&A
GAAP
LIFO
NPNS
PP&E
SAB
VIE
Miscellaneous
EPA
EU
FERC
GHG
HSE
ICC
ICSID
IRS
OTC
NYSE
SEC
TSR
U.K.
U.S.
asset retirement obligation
accounting standards codification
accounting standards update
depreciation, depletion and
amortization
Financial Accounting Standards
Board
first-in, first-out
general and administrative
generally accepted accounting
principles
last-in, first-out
normal purchase normal sale
properties, plants and equipment
staff accounting bulletin
variable interest entity
Environmental Protection Agency
European Union
Federal Energy Regulatory
Commission
greenhouse gas
health, safety and environment
International Chamber of
Commerce
World Bank’s International
Centre for Settlement of
Investment Disputes
Internal Revenue Service
over-the-counter
New York Stock Exchange
U.S. Securities and Exchange
Commission
total shareholder return
United Kingdom
United States of America
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 and “CAUTIONARY STATEMENT FOR THE
PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995,” beginning on page 70.
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
ConocoPhillips is an independent E&P company with operations and activities in 17 countries. Our diverse,
low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional
assets in North America, Europe, Asia and Australia; LNG developments; oil sands assets in Canada; and an
inventory of global conventional and unconventional exploration prospects. Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately 10,400 people worldwide and had total assets of $71
billion.
ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in
anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between
Conoco and Phillips was consummated on August 30, 2002.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 25—Segment Disclosures and Related
Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. At December 31, 2019, our operations were producing in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, Malaysia, Libya, China and Qatar.
The information listed below appears in the “Oil and Gas Operations” disclosures following the Notes to
Consolidated Financial Statements and is incorporated herein by reference:
• Proved worldwide crude oil, NGLs, natural gas and bitumen reserves.
• Net production of crude oil, NGLs, natural gas and bitumen.
• Average sales prices of crude oil, NGLs, natural gas and bitumen.
• Average production costs per BOE.
• Net wells completed, wells in progress and productive wells.
• Developed and undeveloped acreage.
2
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.
Net Proved Reserves at December 31
Crude oil
Consolidated operations
Equity affiliates
Total Crude Oil
Natural gas liquids
Consolidated operations
Equity affiliates
Total Natural Gas Liquids
Natural gas
Consolidated operations
Equity affiliates
Total Natural Gas
Bitumen
Consolidated operations
Total Bitumen
Total consolidated operations
Total equity affiliates
Total company
Millions of Barrels of Oil Equivalent
2019
2018
2017
2,562
73
2,635
361
39
400
1,209
736
1,945
282
282
4,414
848
5,262
2,533
78
2,611
349
42
391
1,265
760
2,025
236
236
4,383
880
5,263
2,322
83
2,405
354
45
399
1,267
717
1,984
250
250
4,193
845
5,038
Total production of 1,348 MBOED increased 5 percent in 2019 compared with 2018. The increase in total
average production primarily resulted from new wells online in the Lower 48; an increased interest in the
Western North Slope (WNS) and Greater Kuparuk Area (GKA) of Alaska following acquisitions closed in
2018; and higher production in Norway due to drilling activity and the startup of Aasta Hansteen in December
2018. The increase in production was partly offset by normal field decline and disposition impacts, primarily
from the U.K. asset sale in 2019 and non-core asset sales in the Lower 48 during 2018.
3
Production excluding Libya was 1,305 MBOED in 2019 compared with 1,242 MBOED in 2018, an increase of
63 MBOED or 5 percent. Underlying production, which excludes Libya and the net volume impact from
closed dispositions and acquisitions of 51 MBOED in 2019 and 47 MBOED in 2018, is used to measure our
ability to grow production organically. Our underlying production grew 5 percent to 1,254 MBOED in 2019
from 1,195 MBOED in 2018.
Our worldwide annual average realized price was $48.78 per BOE in 2019, a decrease of 9 percent compared
with $53.88 per BOE in 2018, reflecting weaker marker prices as a result of macroeconomic demand concerns.
Our worldwide annual average crude oil price decreased 10 percent, from $68.13 per barrel in 2018 to $60.99
per barrel in 2019. Additionally, our worldwide annual average NGL prices decreased 34 percent, from
$30.48 per barrel in 2018 to $20.09 per barrel in 2019. Our worldwide annual average natural gas price
decreased 11 percent, from $5.65 per MCF in 2018 to $5.03 per MCF in 2019. Average annual bitumen prices
increased 42 percent, from $22.29 per barrel in 2018 to $31.72 per barrel in 2019.
ALASKA
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and NGLs.
We are the largest crude oil producer in Alaska and have major ownership interests in two of North America’s
largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk. We also have a 100 percent
interest in the Alpine Field, located on the Western North Slope. Additionally, we are one of Alaska’s largest
owners of state, federal and fee exploration leases, with approximately 1.32 million net undeveloped acres at
year-end 2019. Alaska operations contributed 25 percent of our worldwide liquids production and less than 1
percent of our natural gas production.
Average Daily Net Production
Greater Prudhoe Area
Greater Kuparuk Area
Western North Slope
Total Alaska
Interest
Operator
36.1 %
91.4-94.7
100.0
BP
ConocoPhillips
ConocoPhillips
Liquids
MBD
2019
Natural Gas
MMCFD
Total
MBOED
81
86
50
217
4
2
1
7
81
86
51
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.
4
Western North Slope
On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three
satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. In 2015, first oil was
achieved at Alpine West CD5, a drill site which extends the Alpine reservoir west into the National Petroleum
Reserve-Alaska (NPR-A). In 2019, we continued drilling additional wells using the available well slots on this
pad.
The Greater Mooses Tooth Unit, the first unit established entirely within the NPR-A, was formed in 2008. In
2017, we began construction in the unit with two drill sites; Greater Mooses Tooth #1 (GMT-1) and Greater
Mooses Tooth #2 (GMT-2). GMT-1 achieved first oil in the fourth quarter of 2018 and completed drilling in
2019. We expect first oil from GMT-2 in 2021.
Alaska North Slope Gas
In 2016, we, along with affiliates of Exxon Mobil Corporation, BP p.l.c. and Alaska Gasline Development
Corporation (AGDC), a state-owned corporation, completed preliminary FEED technical work for a potential
LNG project which would liquefy and export natural gas from Alaska’s North Slope and deliver it to
market. In 2016, we, along with the affiliates of ExxonMobil and BP, indicated our intention not to progress
into the next phase of the project due to changes in the economic environment. AGDC decided to continue on
its own. In 2019, affiliates of ExxonMobil and BP agreed to each contribute up to $5 million or approximately
one third of AGDC’s anticipated costs for full-year 2020. In 2020, AGDC will be focused on permitting
efforts, the most important of which is the National Environmental Protection Act process before the FERC.
FERC’s final milestones are the Publication of Notice of Availability of Final Environmental Impact
Statement, which is scheduled for March 6, 2020, and the Issuance of Final Order, which is scheduled for June
4, 2020. AGDC has recently contracted with Fluor Corporation to evaluate cost reduction opportunities in
preparation for soliciting partners for the project. We continue to be willing to sell our North Slope gas to the
project but do not plan to take an equity position.
Exploration
Appraisal of the Willow Discovery, located in the northeast portion of the NPR-A, continued throughout 2019
with five appraisal wells. In 2020, we will continue appraisal of the Willow Discovery and explore the
Harpoon Prospect, located southwest of Willow.
In 2019, we drilled the West Willow-2 well to appraise the 2018 West Willow oil discovery.
In late 2018, we commenced appraisal of the Putu Discovery with a long reach well from existing Alpine CD4
infrastructure. The CD4 appraisal well finished drilling and flow tested in 2019. A supporting injector well
was drilled in late 2019 for a 2020 injectivity test.
The Cairn 2S-315 Well was drilled in late 2018 from the 2S drill site on state leases in the Kuparuk River Unit.
A long-term flow test was commenced in 2019 and evaluations are ongoing.
A 3-D seismic survey was completed in 2018 over a 250-mile area on state lands. We are currently evaluating
this seismic data for future exploration opportunities.
We were successful in the federal lease sale on the North Slope in the fourth quarter of 2019, where we were
the high bidder on three tracts for a total of approximately 33,000 net acres.
Acquisitions
In the third quarter of 2019, we completed the Nuna discovery acreage acquisition, expanding the Kuparuk
River Unit by 21,000 acres and leveraging legacy infrastructure.
5
Transportation
We transport the petroleum liquids produced on the North Slope to south central Alaska through an 800-mile
pipeline that is part of Trans-Alaska Pipeline System (TAPS). We have a 29.1 percent ownership interest in
TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope.
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope
production, using five company-owned, double-hulled tankers, and charters third-party vessels as necessary.
The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.
LOWER 48
The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico.
Organized into the Gulf Coast and Great Plains business units, we hold 10.4 million net onshore and offshore
acres, with a portfolio of conventional production from legacy assets as well as newer production from our low
cost of supply, shorter cycle time, resource-rich unconventional plays. Based on 2019 production volumes, the
Lower 48 is the company’s largest segment and contributed 39 percent of our worldwide liquids production
and 22 percent of our natural gas production.
Interest
Operator
Liquids
MBD
2019
Natural Gas
MMCFD
Total
MBOED
Various
Various
Various
Various %
Various
Various
Average Daily Net Production
Eagle Ford
Gulf of Mexico
Gulf Coast—Other
Total Gulf Coast
Bakken
Permian Unconventional
Permian Conventional
Anadarko Basin
Wyoming/Uinta
Niobrara*
Total Great Plains
174
15
3
192
82
40
20
5
-
8
155
347
Total Lower 48
*Classified as held-for-sale as of December 31, 2019. See 'Dispositions' below for additional information.
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
251
11
9
271
92
94
59
58
36
12
351
622
216
16
5
237
97
56
30
14
6
11
214
451
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.
6
The majority of our 2019 onshore production originated from the Big 3—Eagle Ford, Bakken and Permian
Unconventional. Onshore activities in 2019 were centered mostly on continued development of assets, with an
emphasis on areas with low cost of supply, particularly in growing unconventional plays. Our major focus
areas in 2019 included the following:
• Eagle Ford—The Eagle Ford continued full-field development in 2019. We operated seven rigs on
average in 2019, resulting in 155 operated wells drilled and 166 operated wells brought online.
Production increased 16 percent in 2019 compared with 2018, averaging 216 MBOED and 186
MBOED, respectively.
• Bakken—We operated an average of three rigs during the year in the Bakken and participated in
additional development activities operated by co-venturers. We continued our pad drilling with 62
operated wells drilled during the year and 44 operated wells brought online. Production increased 15
percent in 2019 compared with 2018, averaging 97 MBOED and 84 MBOED, respectively.
• Permian Basin—The Permian Basin is a combination of legacy conventional and unconventional
assets. We operated an average of three rigs during the year in the Permian Basin, resulting in 29
operated wells drilled and 35 operated wells brought online. The Permian Basin produced 86
MBOED in 2019, increasing 30 percent compared with 2018, including 56 MBOED of
unconventional production.
Gulf of Mexico
At year-end 2019, our portfolio of producing properties in the Gulf of Mexico totaled approximately 60,000
net acres. A majority of the production consists of three fields operated by co-venturers:
• 15.9 percent nonoperated working interest in the unitized Ursa Field located in the Mississippi Canyon
Area.
• 15.9 percent nonoperated working interest in the Princess Field, a northern subsalt extension of the
Ursa Field.
• 12.4 percent nonoperated working interest in the unitized K2 Field, comprised of seven blocks in the
Green Canyon Area.
Dispositions
We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass
Pipeline near Sabine Pass, Texas, intended to provide us with terminal and pipeline capacity for the receipt,
storage and regasification of LNG purchased from Qatar Liquefied Gas Company Limited (3) (QG3). We
previously held a 12.4 percent interest in Golden Pass LNG Terminal and Golden Pass Pipeline, but we sold
those interests in the second quarter of 2019 while retaining the basic use agreements.
In the fourth quarter of 2019, we completed the sale of our interests in the Magnolia Field in the Gulf of
Mexico. Production from this disposed asset was less than one MBOED in 2019.
In the fourth quarter of 2019, we entered into an agreement to sell our interests in the Niobrara, with an
anticipated closing date in the first quarter of 2020. Production from the interests to be disposed was
approximately 11 MBOED in 2019.
In January 2020, we entered into an agreement to sell our interests in certain non-core properties for $186
million, plus customary adjustments. The assets met the held for sale criteria in January 2020 and the
transaction is expected to be completed in the first quarter of 2020. This disposition will not have a significant
impact on Lower 48 production.
For additional information on these transactions, see Note 5—Asset Acquisitions and Dispositions, in the
Notes to Consolidated Financial Statements.
7
Exploration
Our exploration focus is on onshore unconventional plays, which in 2019 included the Delaware in the
Permian Basin, and the Eagle Ford in south Texas. In the third quarter of 2019, we announced our decision to
discontinue exploration activities in the Central Louisiana Austin Chalk.
Facilities
• Lost Cabin Gas Plant—We operate and own a 46 percent interest in the Lost Cabin Gas Plant, a 246
MMCFD capacity natural gas processing facility in Lysite, Wyoming. The plant is currently operating at
less than capacity due to a fire in December 2018. Restoration efforts are ongoing and anticipated to be
completed in the second half of 2020. The expected production loss in 2020 is immaterial to the segment.
• Helena Condensate Processing Facility—We operate and own the Helena Condensate Processing Facility,
a 110 MBD condensate processing plant located in Kenedy, Texas.
• Sugarloaf Condensate Processing Facility—We operate and own an 87.5 percent interest in the Sugarloaf
Condensate Processing Facility, a 30 MBD condensate processing plant located near Pawnee, Texas.
• Bordovsky Condensate Processing Facility—We operate and own the Bordovsky Condensate Processing
Facility, a 15 MBD condensate processing plant located in Kenedy, Texas.
8
CANADA
Our Canadian operations mainly consist of the Surmont oil sands development in Alberta and the liquids-rich
Montney unconventional play in British Columbia. In 2019, operations in Canada contributed 7 percent of our
worldwide liquids production and less than 1 percent of our natural gas production.
2019
Natural
Interest
Operator
MBD MMCFD MBD
Liquids
Gas Bitumen
Total
MBOED
Average Daily Net Production
Surmont
Montney
Total Canada
50.0 % ConocoPhillips
ConocoPhillips
100.0
-
1
1
-
9
9
60
-
60
60
3
63
Surmont
Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called SAGD,
whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and
pumped to the surface for further processing. We hold approximately 0.6 million net acres of land in the
Athabasca Region of northeastern Alberta.
The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta. Surmont
is a 50/50 joint venture with Total S.A. The second phase of the Surmont Project achieved first production in
2015 and reached peak production in 2018. We are focused on structurally lowering costs, reducing GHG
intensity and optimizing asset performance.
The Alberta government imposed a production curtailment impacting the industry beginning in January 2019.
The curtailment measure, which impacted our annualized average production by 3 MBOED in 2019, is
intended to strengthen the WCS differential to WTI at Hardisty. The curtailment program is established and
administered by the Alberta Energy Regulator under the Curtailment Rules regulation, which is currently set to
expire on December 31, 2020.
Montney
We hold approximately 151,000 net acres in the emerging unconventional Montney play in northeast British
Columbia. Our Montney activity in 2019 included drilling 16 horizontal wells, completing 14 horizontal wells
and acquiring approximately 6,000 additional net acres. Production from our 2019 drilling program
commenced in February 2020 following the completion of third-party offtake facilities.
Appraisal drilling and completions activity will continue in 2020 to further explore the area’s resource
potential.
Exploration
Our primary exploration focus is assessing our Montney onshore unconventional acreage in Western Canada.
Additionally, we have exploration acreage in the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands.
9
EUROPE AND NORTH AFRICA
The Europe and North Africa segment consisted of operations in Norway, Libya and the U.K. and exploration
activities in Norway and Libya. In 2019, operations in Europe and North Africa contributed 16 percent of our
worldwide liquids production and 17 percent of natural gas production.
Norway
Average Daily Net Production
Greater Ekofisk Area
Heidrun
Alvheim
Visund
Aasta Hansteen
Troll
Other
Total Norway
Interest
Operator
35.1 % ConocoPhillips
Equinor
24.0
Aker BP
20.0
Equinor
9.1
Equinor
10.0
Equinor
1.6
Equinor
Various
2019
Liquids Natural Gas
Total
MBD MMCFD MBOED
50
14
10
4
-
2
8
88
44
29
12
46
64
49
10
254
57
19
12
12
11
10
10
131
The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway, in the North Sea,
and comprises three producing fields: Ekofisk, Eldfisk and Embla. Crude oil is exported to Teesside, England,
and the natural gas is exported to Emden, Germany. The Ekofisk and Eldfisk fields consist of several
production platforms and facilities, including the Ekofisk South and Eldfisk II developments. Continued
development drilling in the Greater Ekofisk Area is expected to contribute additional production over the
coming years, as additional wells come online.
The Heidrun Field is located in the Norwegian Sea. Produced crude oil is stored in a floating storage unit and
exported via shuttle tankers. Part of the natural gas is currently injected into the reservoir for optimization of
crude oil production, some gas is transported for use as feedstock in a methanol plant in Norway, in which we
own an 18 percent interest, and the remainder is transported to Europe via gas processing terminals in Norway.
The Alvheim Field is located in the northern part of the North Sea near the border with the U.K. sector, and
consists of a FPSO vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and
natural gas is transported to the Scottish Area Gas Evacuation (SAGE) Terminal at St. Fergus, Scotland,
through the SAGE Pipeline.
Visund is an oil and gas field located in the North Sea and consists of a floating drilling, production and
processing unit, and subsea installations. Crude oil is transported by pipeline to a nearby third-party field for
storage and export via tankers. The natural gas is transported to a gas processing plant at Kollsnes, Norway,
through the Gassled transportation system.
Aasta Hansteen is located in the Norwegian Sea and achieved first production in December 2018. Produced
condensate is loaded onto shuttle tankers and transported to market. Gas is transported through the Polarled
gas pipeline to the onshore Nyhamna processing plant for final processing prior to export to market.
The Troll Field lies in the northern part of the North Sea and consists of the Troll A, B and C platforms. The
natural gas from Troll A is transported to Kollsnes, Norway. Crude oil from floating platforms Troll B and
Troll C is transported to Mongstad, Norway, for storage and export.
We also have varying ownership interests in two other producing fields in the Norway sector of the North Sea.
10
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
Interest
Operator
Average Daily Net Production
Britannia Satellites*
J-Area
Britannia
East Irish Sea
Clair
Other
Total United Kingdom
*Includes the Chevron-operated Alder Field, ConocoPhillips equity interest was 26.3 percent.
26.3–93.8 % ConocoPhillips
32.5–36.5
ConocoPhillips
58.7 ConocoPhillips
Spirit Energy
100.0
7.5
BP
Various
Various
2019
Liquids
Natural
Gas
MBD MMCFD
Total
MBOED
7
6
2
-
4
-
19
55
38
49
48
1
2
193
16
12
10
8
4
-
50
On September 30, 2019, we completed the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P
Limited, including all of our producing assets in the U.K. Annualized average production from the assets sold
was 50 MBOED in 2019. For additional information on this transaction, see Note 5—Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial Statements.
We retained our Teesside, England oil terminal, where we are the operator and have a 40.25 percent ownership
interest, to support our Norway operations.
Libya
Interest
Operator
Liquids
MBD
2019
Natural
Gas
Total
MMCFD MBOED
Average Daily Net Production
Waha Concession
Total Libya
16.3 %
Waha Oil Co.
38
38
31
31
43
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
11
blockade of the Es Sider crude oil export terminal and the declaration of Force Majeure by the National Oil
Corporation of Libya.
ASIA PACIFIC AND MIDDLE EAST
The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia,
Malaysia and Australia and producing operations in Qatar and Timor-Leste. In 2019, operations in the Asia
Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 60 percent of
natural gas production.
Australia and Timor-Leste
2019
Average Daily Net Production
Interest
Operator
Natural
Gas
Liquids
Total
MBD MMCFD MBOED
Australia Pacific LNG
Bayu-Undan*
Athena/Perseus*
Total Australia and Timor-Leste
*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.
37.5 %
56.9
50.0
679
194
31
904
-
10
-
10
113
43
5
161
ConocoPhillips/
Origin Energy
ConocoPhillips
ExxonMobil
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.
12
Bayu-Undan
The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between
Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG
Facility, located at Wickham Point, Darwin.
The Bayu-Undan natural gas recycle facility processes wet gas; separates, stores and offloads condensate,
propane and butane; and re-injects dry gas back into the reservoir. In addition, a 310-mile natural gas pipeline
connects the facility to the 3.5-million-metric-tonnes-per-year capacity Darwin LNG Facility. Produced
natural gas is piped to the Darwin LNG Plant, where it is converted into LNG before being transported to
international markets. In 2019, we sold 133 billion gross cubic feet of LNG primarily to utility customers in
Japan.
Athena/Perseus
The Athena production license (WA-17-L) in which we had a 50 percent working interest is located offshore
Western Australia and our entitlement to production ended in the fourth quarter of 2019. Annualized average
production from this license was five MBOED in 2019.
Exploration
We operate three exploration permits in the Browse Basin, offshore northwest Australia, in which we own a 40
percent interest in permits WA-315-P, WA-398-P and TP 28, of the Greater Poseidon Area. Phase I of the
Browse Basin drilling campaign resulted in three discoveries in the Greater Poseidon Area and Phase II
resulted in five additional discoveries. All wells have been plugged and abandoned.
We operate two retention leases in the Bonaparte Basin, offshore northern Australia, where we own a 37.5
percent interest in the Barossa and Caldita discoveries. In April 2018, Barossa entered the FEED phase of
development which continued through 2019. During the FEED phase, costs and the technical definition for the
project will be finalized, gas and condensate sales agreements progressed, and access arrangements negotiated
with the owners of the Darwin LNG Facility and Bayu-Darwin Pipeline.
In December 2019, we entered into an agreement with 3D Oil to acquire a 75 percent interest and operatorship
of an offshore Tasmanian Permit located in the Otway Basin. The farm-in agreement is conditional upon the
agreement and signing of a JOA by both parties and required government approvals. We plan to conduct a 3D
seismic survey in the second half of 2020. This activity is excluded from the dispositions discussed below.
Dispositions
In the second quarter of 2019, we completed the sale of our 30 percent interest in the Greater Sunrise Fields to
the government of Timor-Leste.
In October 2019, we entered into an agreement to sell the subsidiaries that hold our Australia-West assets and
operations to Santos with an expected completion date in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent. These subsidiaries hold our 37.5 percent interest in the
Barossa Project and Caldita Field, our 56.9 percent interest in the Darwin LNG Facility and Bayu-Undan
Field, our 40 percent interest in the Greater Poseidon Fields, and our 50 percent interest in the Athena Field.
Production associated with the Australia-West assets to be sold was 48 MBOED in 2019.
For additional information on these transactions, see Note 5—Asset Acquisitions and Dispositions, in the
Notes to Consolidated Financial Statements.
13
Indonesia
Average Daily Net Production
South Sumatra
Total Indonesia
Interest
Operator
54 %
ConocoPhillips
2019
Natural
Gas
MBD MMCFD
Liquids
Total
MBOED
2
2
321
321
56
56
During 2019, we operated three PSCs in Indonesia: the Corridor Block and South Jambi “B,” both located in
South Sumatra, and Kualakurun in Central Kalimantan. Currently, we have production from the Corridor
Block.
South Sumatra
The Corridor PSC consists of two oil fields and seven producing natural gas fields. Natural gas is supplied
from the Grissik and Suban gas processing plants to the Duri steamflood in central Sumatra and to markets in
Singapore, Batam and West Java. In 2019, we were awarded a 20-year extension, with new terms, of the
Corridor PSC. Under these terms, we retain a majority interest and continue as operator for at least three years
after 2023 and retain a participating interest until 2043.
Production from the South Jambi “B” PSC has reached depletion and field development has been suspended.
This PSC expired on January 26, 2020 and has been returned to the Government of Indonesia.
Exploration
We hold a 60 percent working interest in the Kualakurun PSC. After completion of prospect evaluation, we
and the other joint venture partners decided to relinquish all of the remaining acreage to the Government of
Indonesia.
Transportation
We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT Transportasi Gas
Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore natural gas pipelines.
China
Average Daily Net Production
Penglai
Panyu
Total China
Interest
Operator
49.0 %
24.5
CNOOC
CNOOC
2019
Natural
Gas
MBD MMCFD
Liquids
Total
MBOED
29
6
35
-
-
-
29
6
35
Penglai
The Penglai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05 and are in various stages of
development.
As part of further development of the Penglai 19-9 Field, the wellhead platform J Project achieved first
production in 2016. This project will include 62 wells, 57 of which have been completed and brought online
through December 2019.
14
The Penglai 19-3/19-9 Phase 3 Project consists of three new wellhead platforms and a central processing
platform. First oil from Phase 3 was achieved in 2018 for two of the platforms, with the third platform planned
to come online in the second quarter of 2020. This project could include up to 186 wells, 42 of which have been
completed and brought online through December 2019.
In December 2018, we sanctioned the Penglai 25-6 Phase 4A Project. This project consists of one new
wellhead platform and anticipates 62 new wells. First production is expected in 2021.
Panyu
Our production license for Panyu 4-2, 5-1 and 11-6 located in Block 15/34 in the South China Sea expired in
September 2019. Annualized average production from these licenses were six MBOED in 2019.
We still have a license for Panyu 4-1 in Block 15/34 and are evaluating this area for potential development.
Exploration
Exploration activities in the Bohai Penglai Field during 2019 consisted of two successful appraisal wells, a
full-field 3-D seismic program covering existing and future development opportunities, and an infill
compressive seismic imaging (CSI) survey to improve imaging beneath the gas cloud in support of future
development projects. In Block 15/34, one exploration well was drilled in the Panyu 4-1E prospect and was
expensed as a dry hole.
Malaysia
Average Daily Net Production
Gumusut
Kebabangan (KBB)
Malikai
Siakap North-Petai
Total Malaysia
Interest
Operator
29.0 %
30.0
35.0
21.0
Shell
KPOC
Shell
PTTEP
2019
Natural
Gas
MBD MMCFD
Liquids
Total
MBOED
23
3
15
1
42
-
91
-
-
91
23
18
15
1
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
15
carries gas production from the KBB gas field to market. The extent of the required pipeline repairs, and the
amount of time required to return this pipeline to full service is still being evaluated.
Kamunsu East
Development options for the Kamunsu East gas field are being evaluated.
Block G
Malikai
We hold a 35 percent working interest in Malikai. This field achieved first production in December 2016 via
the Malikai Tension Leg Platform, ramping to peak production in 2018. The KMU-1 exploration well was
completed and started producing through the Malikai platform in 2018. Malikai Phase 2 development, a 6-
well drilling campaign that will commence in 2020, reached a final investment decision in late 2019.
Siakap North-Petai
We hold a 21 percent working interest in the unitized Siakap North-Petai oil field.
Exploration
In 2016, we entered into a farm-in agreement to acquire a 50 percent working interest in Block SK 313, a 1.4
million gross-acre exploration block offshore Sarawak, with an effective date of January 2017. Following
completion of the Sadok-1 exploration well in January 2017, we assumed operatorship of the block from
PETRONAS and completed a 3-D seismic survey. We have no plans for further exploration activity in this
block.
In 2017, we were awarded operatorship and a 50 percent working interest in Block WL4-00, which included
the existing Salam-1 oil discovery and encompassed 0.6 million gross acres. In 2018 and 2019, two
exploration and two appraisal wells were drilled, resulting in oil discoveries under evaluation at Salam and
Benum, while two Patawali wells were expensed as dry holes in 2019.
In 2018, we were awarded a 50 percent working interest and operatorship of Block SK304 encompassing 2.1
million gross acres offshore Sarawak. We acquired 3-D seismic over the acreage and completed processing of
this data in 2019.
The Gemilang-1 exploration well in Block J was completed in late 2018. Development options are being
evaluated.
Qatar
Interest
Operator
Liquids
MBD
2019
Natural
Gas
Total
MMCFD MBOED
Average Daily Net Production
QG3
Total Qatar
30.0 %
Qatargas Operating
Company Limited
21
21
373
373
83
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.
16
QG3 executed the development of the onshore and offshore assets as a single integrated development with
Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint
development of offshore facilities situated in a common offshore block in the North Field, as well as the
construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and
QG4 joint ventures. Production from the LNG trains and associated facilities is combined and shared.
OTHER INTERNATIONAL
The Other International segment includes exploration activities in Colombia, Chile and Argentina and
contingencies associated with prior operations.
Colombia
We have an 80 percent operated interest in the Middle Magdalena Basin Block VMM-3. The block extends
over approximately 67,000 net acres and contains the Picoplata-1 Well, which completed drilling in 2015 and
testing in 2017. Plug and abandonment activity started during 2018 and completed in 2019. In addition, we
have an 80 percent working interest in the VMM-2 Block which extends over approximately 58,000 net acres
and is contiguous to the VMM-3 Block. As part of a case brought forward by environmental groups, the
Highest Administrative Court granted a preliminary injunction temporarily suspending hydraulic fracturing
activities until the substance of the case is decided. As a result, ConocoPhillips filed two separate Force
Majeure requests before the competent authority for both blocks, which were granted.
Chile
We have a 49 percent interest in the Coiron Block located in the Magallanes Basin in southern Chile.
Argentina
In January 2019, we secured a 50 percent nonoperated interest in the El Turbio Este Block, within the Austral
Basin in southern Argentina. In 2019, we acquired and processed 3-D seismic covering approximately 500
square miles, with evaluation of the data ongoing.
In November 2019, we acquired interests in two nonoperated blocks in the Neuquén Basin targeting the Vaca
Muerta play. We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest in the
Aguada Federal Block. In Bandurria Norte, one vertical and four horizontal wells were tested and shut-in
during 2019. In Aguada Federal, two horizontal wells were being tested at the end of the year.
Venezuela and Ecuador
For discussion of our contingencies in Venezuela and Ecuador, see Note 13—Contingencies and
Commitments, in the Notes to Consolidated Financial Statements.
OTHER
Marketing Activities
Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural
gas, crude oil, bitumen, NGLs and LNG. Marketing activities are performed through offices in the U.S.,
Canada, Europe and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize
realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market
prices at the time of sale. We also purchase and sell third-party volumes to better position the company to
satisfy customer demand while fully utilizing transportation and storage capacity.
Natural Gas
Our natural gas production, along with third-party purchased gas, is primarily marketed in the U.S., Canada,
Europe and Asia. Our natural gas is sold to a diverse client portfolio which includes local distribution
companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas
17
companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport
natural gas via firm and interruptible transportation agreements to major market hubs.
Crude Oil, Bitumen and Natural Gas Liquids
Our crude oil, bitumen and NGL revenues are derived from production in the U.S., Canada, Australia, Asia,
Africa and Europe. These commodities are primarily sold under contracts with prices based on market indices,
adjusted for location, quality and transportation.
LNG
LNG marketing efforts are focused on equity LNG production facilities located in Australia and Qatar. LNG
is primarily sold under long-term contracts with prices based on market indices.
Energy Partnerships
Marine Well Containment Company (MWCC)
We are a founding member of the MWCC, a non-profit organization formed in 2010, which provides well
containment equipment and technology in the deepwater U.S. Gulf of Mexico. MWCC’s containment system
meets the U.S. Bureau of Safety and Environmental Enforcement requirements for a subsea well containment
system that can respond to a deepwater well control incident in the U.S. Gulf of Mexico. For additional
information, see Note 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements.
Subsea Well Response Project (SWRP)
In 2011, we, along with several leading oil and gas companies, launched the SWRP, a non-profit organization
based in Stavanger, Norway, which was created to enhance the industry’s capability to respond to international
subsea well control incidents. Through collaboration with Oil Spill Response Limited, a non-profit
organization in the U.K., subsea well intervention equipment is available for the industry to use in the event of
a subsea well incident. This complements the work being undertaken in the U.S. by MWCC and provides well
capping and containment capability outside the U.S.
Oil Spill Response Removal Organizations (OSROs)
We maintain memberships in several OSROs across the globe as a key element of our preparedness program in
addition to internal response resources. Many of the OSROs are not-for-profit cooperatives owned by the
member companies wherein we may actively participate as a member of the board of directors, steering
committee, work group or other supporting role. Globally, our primary OSRO is Oil Spill Response Ltd.
based in the U.K., with facilities in several other countries and the ability to respond anywhere in the world. In
North America, our primary OSROs include the Marine Spill Response Corporation for the continental United
States and Alaska Clean Seas and Ship Escort/Response Vessel System for the Alaska North Slope and Prince
William Sound, respectively. Internationally, we maintain memberships in various regional OSROs including
the Norwegian Clean Seas Association for Operating Companies, Australian Marine Oil Spill Center and
Petroleum Industry of Malaysia Mutual Aid Group.
Technology
We have several technology programs that improve our ability to develop unconventional reservoirs, produce
heavy oil economically with less emissions, improve the efficiency of our exploration program, increase
recoveries from our legacy fields, and implement sustainability measures.
Our Optimized Cascade® LNG liquefaction technology business continues to be successful with the demand
for new LNG plants. The technology has been licensed for use in 26 LNG trains around the world, with
feasibility studies ongoing for additional trains.
18
RESERVES
We have not filed any information with any other federal authority or agency with respect to our estimated
total proved reserves at December 31, 2019. No difference exists between our estimated total proved reserves
for year-end 2018 and year-end 2017, which are shown in this filing, and estimates of these reserves shown in
a filing with another federal agency in 2019.
DELIVERY COMMITMENTS
We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements,
some of which specify the delivery of a fixed and determinable quantity. Our commercial organization also
enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the
spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed
to deliver approximately 1.1 trillion cubic feet of natural gas, including approximately 75 billion cubic feet
related to the noncontrolling interests of consolidated subsidiaries, and 172 million barrels of crude oil in the
future. These contracts have various expiration dates through the year 2030. We expect to fulfill the majority
of these delivery commitments with proved developed reserves. In addition, we anticipate using PUDs and
spot market purchases to fulfill any remaining commitments. See the disclosure on “Proved Undeveloped
Reserves” in the “Oil and Gas Operations” section following the Notes to Consolidated Financial Statements,
for information on the development of PUDs.
COMPETITION
We compete with private, public and state-owned companies in all facets of the E&P business. Some of our
competitors are larger and have greater resources. Each of our segments is highly competitive, with no single
competitor, or small group of competitors, dominating.
We compete with numerous other companies in the industry, including state-owned companies, to locate and
obtain new sources of supply and to produce oil, bitumen, NGLs and natural gas in an efficient, cost-effective
manner. Based on statistics published in the September 2, 2019, issue of the Oil and Gas Journal, we were the
third-largest U.S.-based oil and gas company in worldwide natural gas and liquids production and worldwide
liquids reserves in 2018. We deliver our production into the worldwide commodity markets. Principal
methods of competing include geological, geophysical and engineering research and technology; experience
and expertise; economic analysis in connection with portfolio management; and safely operating oil and gas
producing properties.
GENERAL
At the end of 2019, we held a total of 942 active patents in 50 countries worldwide, including 371 active U.S.
patents. During 2019, we received 64 patents in the U.S. and 90 foreign patents. Our products and processes
generated licensing revenues of $69 million related to activity in 2019. The overall profitability of any
business segment is not dependent on any single patent, trademark, license, franchise or concession.
19
Health, Safety and Environment
Our HSE organization provides tools and support to our business units and staff groups to help them ensure
world class HSE performance. The framework through which we safely manage our operations, the HSE
Management System Standard, emphasizes process safety, risk management, emergency preparedness and
environmental performance, with an intense focus on process and occupational safety. In support of the goal
of zero incidents, HSE milestones and criteria are established annually to drive strong safety and
environmental performance. Progress toward these milestones and criteria are measured and reported. HSE
audits are conducted on business functions periodically, and improvement actions are established and tracked
to completion. We have designed processes relating to sustainable development in our economic,
environmental and social performance. Our processes, related tools and requirements focus on water,
biodiversity and climate change, as well as social and stakeholder issues.
The environmental information contained in Management’s Discussion and Analysis of Financial Condition
and Results of Operations on pages 60 through 65 under the captions “Environmental” and “Climate Change”
is incorporated herein by reference. It includes information on expensed and capitalized environmental costs
for 2019 and those expected for 2020 and 2021.
Website Access to SEC Reports
Our internet website address is www.conocophillips.com. Information contained on our internet website is not
part of this report on Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any
amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange
Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports
are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at
www.sec.gov.
20
Item 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this
Annual Report on Form 10-K. These risk factors are not the only risks we face. Our business could also be
affected by additional risks and uncertainties not currently known to us or that we currently consider to be
immaterial. If any of these risks were to occur, our business, operating results and financial condition, as well
as the value of an investment in our common stock could be adversely affected.
Our operating results, our future rate of growth and the carrying value of our assets are exposed to the
effects of changing commodity prices.
Prices for crude oil, bitumen, natural gas, NGLs and LNG can fluctuate widely. Brent crude oil prices
averaged $64 per barrel in 2019, ranging from a low of $53 per barrel in January to a high of almost $75 per
barrel in April. Given volatility in commodity price drivers and the worldwide political and economic
environment generally, as well as increased uncertainty generated by recent (and potential future) armed
hostilities in various oil-producing regions around the globe, price trends may continue to be volatile. Our
revenues, operating results and future rate of growth are highly dependent on the prices we receive for our
crude oil, bitumen, natural gas, NGLs and LNG. The factors influencing these prices are beyond our control.
Lower crude oil, bitumen, natural gas, NGL and LNG prices may have a material adverse effect on our
revenues, operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to
declare and pay on our common stock and the amount of shares we elect to acquire as part of the share
repurchase program and the timing of such acquisitions. Lower prices may also limit the amount of reserves
we can produce economically, adversely affecting our proved reserves, reserve replacement ratio and
accelerating the reduction in our existing reserve levels as we continue production from upstream fields.
Significant reductions in crude oil, bitumen, natural gas, NGLs and LNG prices could also require us to reduce
our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain
assets as proved reserves. In the past three years, we recognized several impairments, which are described in
Note 9—Impairments and the “APLNG” section of Note 6—Investments, Loans and Long-Term Receivables,
in the Notes to Consolidated Financial Statements. If commodity prices remain low relative to their historic
levels, and as we continue to optimize our investments and exercise capital flexibility, it is reasonably likely
we will incur future impairments to long-lived assets used in operations, investments in nonconsolidated
entities accounted for under the equity method and unproved properties. Although it is not reasonably
practicable to quantify the impact of any future impairments at this time, our results of operations could be
adversely affected as a result.
Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.
Dividends are authorized and determined by our Board of Directors in its sole discretion and depend upon a
number of factors, including:
• Cash available for distribution.
• Our results of operations and anticipated future results of operations.
• Our financial condition, especially in relation to the anticipated future capital needs of our properties.
• The level of distributions paid by comparable companies.
• Our operating expenses.
• Other factors our Board of Directors deems relevant.
We expect to continue to pay quarterly dividends to our stockholders; however, our Board of Directors may
reduce our dividend or cease declaring dividends at any time, including if it determines that our net cash
provided by operating activities, after deducting capital expenditures and investments, are not sufficient to pay
our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all.
21
Additionally, as of December 31, 2019, $5.4 billion of repurchase authority remained of the $15 billion share
repurchase program our Board of Directors had authorized. In February, 2020, our Board of Directors
approved an increase to our repurchase authorization from $15 billion to $25 billion, to support our plan for
future share repurchases. Our share repurchase program does not obligate us to acquire a specific number of
shares during any period, and our decision to commence, discontinue or resume repurchases in any period will
depend on the same factors that our Board of Directors may consider when declaring dividends, among others.
Any downward revision in the amount of dividends we pay to stockholders or the number of shares we
purchase under our share repurchase program could have an adverse effect on the market price of our common
stock.
We may need additional capital in the future, and it may not be available on acceptable terms.
We have historically relied primarily upon cash generated by our operations to fund our operations and
strategy; however, we have also relied from time to time on access to the debt and equity capital markets for
funding. There can be no assurance that additional debt or equity financing will be available in the future on
acceptable terms, or at all. In addition, although we anticipate we will be able to repay our existing
indebtedness when it matures or in accordance with our stated plans, there can be no assurance we will be able
to do so. Our ability to obtain additional financing, or refinance our existing indebtedness when it matures or
in accordance with our plans, will be subject to a number of factors, including market conditions, our operating
performance, investor sentiment and our ability to incur additional debt in compliance with agreements
governing our then-outstanding debt. If we are unable to generate sufficient funds from operations or raise
additional capital for any reason, our business could be adversely affected.
In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including
our financial strength and conditions affecting the oil and gas industry generally. We and other industry
companies have had their ratings reduced in the past due to negative commodity price outlooks. Any
downgrade in our credit rating or announcement that our credit rating is under review for possible downgrade
could increase the cost associated with any additional indebtedness we incur.
Our business may be adversely affected by deterioration in the credit quality of, or defaults under our
contracts with, third parties with whom we do business.
The operation of our business requires us to engage in transactions with numerous counterparties operating in a
variety of industries, including other companies operating in the oil and gas industry. These counterparties
may default on their obligations to us as a result of operational failures or a lack of liquidity, or for other
reasons, including bankruptcy. Market speculation about the credit quality of these counterparties, or their
ability to continue performing on their existing obligations, may also exacerbate any operational difficulties or
liquidity issues they are experiencing, particularly as it relates to other companies in the oil and gas industry as
a result of the volatility in commodity prices. Any default by any of our counterparties may result in our
inability to perform our obligations under agreements we have made with third parties or may otherwise
adversely affect our business or results of operations. In addition, our rights against any of our counterparties
as a result of a default may not be adequate to compensate us for the resulting harm caused or may not be
enforceable at all in some circumstances. We may also be forced to incur additional costs as we attempt to
enforce any rights we have against a defaulting counterparty, which could further adversely impact our results
of operations.
In particular, in August 2018, we entered into a settlement agreement with Petróleos de Venezuela, S.A.
(PDVSA) providing for the payment of approximately $2 billion over a five-year period in connection with an
arbitration award issued by the International Chamber of Commerce (ICC) Tribunal in favor of ConocoPhillips
on a contractual dispute arising from Venezuela’s expropriation of our interests in the Petrozuata and Hamaca
heavy oil ventures and other pre-expropriation fiscal measures. We collected approximately $0.8 billion of the
$2.0 billion settlement in 2018 and 2019. PDVSA has defaulted on its remaining payment obligations under
this agreement, we are therefore now forced to incur additional costs as we seek to recover any unpaid amounts
under the agreement.
22
Unless we successfully add to our existing proved reserves, our future crude oil, bitumen, natural gas and
NGL production will decline, resulting in an adverse impact to our business.
The rate of production from upstream fields generally declines as reserves are depleted. If we do not conduct
successful exploration and development activities, or, through engineering studies, optimize production
performance or identify additional or secondary recovery reserves, our proved reserves will decline materially
as we produce crude oil, bitumen, natural gas and NGLs, and our business will experience reduced cash flows
and results of operations. Any cash conservation efforts we may undertake as a result of commodity price
declines may further limit our ability to replace depleted reserves.
The exploration and production of oil and gas is a highly competitive industry.
The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business.
We compete with private, public and state-owned companies in all facets of the exploration and production
business, including to locate and obtain new sources of supply and to produce oil, bitumen, natural gas and
NGLs in an efficient, cost-effective manner. Some of our competitors are larger and have greater resources
than we do or may be willing to incur a higher level of risk than we are willing to incur to obtain potential
sources of supply. If we are not successful in our competition for new reserves, our financial condition and
results of operations may be adversely affected.
Any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural
gas and NGL reserves could impair the quantity and value of those reserves.
Our proved reserve information included in this annual report represents management’s best estimates based
on assumptions, as of a specified date, of the volumes to be recovered from underground accumulations of
crude oil, bitumen, natural gas and NGLs. Such volumes cannot be directly measured and the estimates and
underlying assumptions used by management are subject to substantial risk and uncertainty. Any material
changes in the factors and assumptions underlying our estimates of these items could result in a material
negative impact to the volume of reserves reported or could cause us to incur impairment expenses on property
associated with the production of those reserves. Future reserve revisions could also result from changes in,
among other things, governmental regulation.
We expect to continue to incur substantial capital expenditures and operating costs as a result of our
compliance with existing and future environmental laws and regulations.
Our business is subject to numerous laws and regulations relating to the protection of the environment, which
are expected to continue to have an increasing impact on our operations in the U.S. and in other countries in
which we operate. For a description of the most significant of these environmental laws and regulations, see
the “Contingencies—Environmental” section of Management’s Discussion and Analysis of Financial
Condition and Results of Operations. These laws and regulations continue to increase in both number and
complexity and affect our operations with respect to, among other things:
• Permits required in connection with exploration, drilling, production and other activities.The
discharge of pollutants into the environment.
• Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and GHG emissions.
• Carbon taxes.
• The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous
and nonhazardous wastes.
• The dismantlement, abandonment and restoration of our properties and facilities at the end of their
useful lives.
• Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil
sands reservoirs and unconventional plays.
23
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation
expenditures as a result of these laws and regulations. Any failure by us to comply with existing or future
laws, regulations and other requirements could result in administrative or civil penalties, criminal fines, other
enforcement actions or third-party litigation against us. To the extent these expenditures, as with all costs, are
not ultimately reflected in the prices of our products and services, our business, financial condition, results of
operations and cash flows in future periods could be materially adversely affected.
Existing and future laws, regulations and initiatives relating to global climate change, such as limitations
on GHG emissions, may impact or limit our business plans, result in significant expenditures, promote
alternative uses of energy or reduce demand for our products.
Continuing political and social attention to the issue of global climate change has resulted in both existing and
pending international agreements and national, regional or local legislation and regulatory measures to limit
GHG emissions, such as cap and trade regimes, carbon taxes, restrictive permitting, increased fuel efficiency
standards and incentives or mandates for renewable energy. For example, in December 2015, the U.S. joined
the international community at the 21st Conference of the Parties of the United Nations Framework
Convention on Climate Change in Paris that prepared an agreement requiring member countries to review and
represent a progression in their intended GHG emission reduction goals every five years beginning in 2020.
While the U.S. announced its intention to withdraw from the Paris Agreement, there is no guarantee that the
commitments made by the U.S. will not be implemented, in whole or in part, by U.S. state and local
governments or by major corporations headquartered in the U.S. In addition, our operations continue in
countries around the world which are party to, and have not announced an intent to withdraw from, the Paris
Agreement. The implementation of current agreements and regulatory measures, as well as any future
agreements or measures addressing climate change and GHG emissions, may adversely impact the demand for
our products, impose taxes on our products or operations or require us to purchase emission credits or reduce
emission of GHGs from our operations. As a result, we may experience declines in commodity prices or incur
substantial capital expenditures and compliance, operating, maintenance and remediation costs, any of which
may have an adverse effect on our business and results of operations.
Additionally, increasing attention to global climate change has resulted in pressure upon shareholders,
financial institutions and/or financial markets to modify their relationships with oil and gas companies and to
limit investments and/or funding to such companies, which could increase our costs or otherwise adversely
affect our business and results of operations.
Furthermore, increasing attention to global climate change has resulted in an increased likelihood of
governmental investigations and private litigation, which could increase our costs or otherwise adversely affect
our business. In 2017 and 2018, cities, counties, and a state government in California, New York, Washington,
Rhode Island and Maryland, as well as the Pacific Coast Federation of Fishermen’s Association, Inc., filed
lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and
equitable relief to abate alleged climate change impacts. ConocoPhillips is vigorously defending against these
lawsuits. The ultimate outcome and impact to us cannot be predicted with certainty, and we could incur
substantial legal costs associated with defending these and similar lawsuits in the future.
In addition, although we design and operate our business operations to accommodate expected climatic
conditions, to the extent there are significant changes in the earth’s climate, such as more severe or frequent
weather conditions in the markets where we operate or the areas where our assets reside, we could incur
increased expenses, our operations could be adversely impacted, and demand for our products could fall.
For more information on legislation or precursors for possible regulation relating to global climate change that
affect or could affect our operations and a description of the company’s response, see the “Contingencies—
Climate Change” section of Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
24
Domestic and worldwide political and economic developments could damage our operations and materially
reduce our profitability and cash flows.
Actions of the U.S., state, local and foreign governments, through sanctions, tax and other legislation,
executive order and commercial restrictions, could reduce our operating profitability both in the U.S. and
abroad. In certain locations, governments have imposed or proposed restrictions on our operations; special
taxes or tax assessments; and payment transparency regulations that could require us to disclose competitively
sensitive information or might cause us to violate non-disclosure laws of other countries.
One area subject to significant political and regulatory activity is the use of hydraulic fracturing, an essential
completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability
rock formations. A range of local, state, federal and national laws and regulations currently govern or, in some
hydraulic fracturing operations, prohibit hydraulic fracturing in some jurisdictions. Although hydraulic
fracturing has been conducted for many decades, a number of new laws, regulations and permitting
requirements are under consideration by the U.S. EPA and others which could result in increased costs,
operating restrictions, operational delays or limit the ability to develop oil and natural gas resources. Certain
jurisdictions in which we operate, including state and local governments in Colorado, have adopted or are
considering regulations that could impose new or more stringent permitting, disclosure or other regulatory
requirements on hydraulic fracturing or other oil and natural-gas operations, including subsurface water
disposal. In addition, certain interest groups have also proposed ballot initiatives and constitutional
amendments designed to restrict oil and natural-gas development generally and hydraulic fracturing in
particular. For example, in 2018, Colorado voters rejected Proposition 112, a Colorado ballot initiative that
would have drastically limited the use of hydraulic fracturing in Colorado. In the event that ballot initiatives,
local or state restrictions or prohibitions are adopted and result in more stringent limitations on the production
and development of oil and natural gas in areas where we conduct operations, we may incur significant costs to
comply with such requirements or may experience delays or curtailment in the permitting or pursuit of
exploration, development or production activities. Such compliance costs and delays, curtailments, limitations
or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial
condition and liquidity.
The U.S. government can also prevent or restrict us from doing business in foreign countries. These
restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access
to, opportunities in various countries. Actions by host governments, such as the expropriation of our oil assets
by the Venezuelan government, have affected operations significantly in the past and may continue to do so in
the future. Changes in domestic and international regulations may affect our ability to collect payments such
as those pertaining to the settlement with PDVSA or the ICSID Award against the Government of Venezuela;
or to obtain or maintain permits, including those necessary for drilling and development of wells in various
locations.
Local political and economic factors in international markets could have a material adverse effect on us.
Approximately 50 percent of our hydrocarbon production was derived from production outside the U.S. in
2019, and 39 percent of our proved reserves, as of December 31, 2019, were located outside the U.S. We are
subject to risks associated with operations in international markets, including changes in foreign governmental
policies relating to crude oil, natural gas, bitumen, NGLs or LNG pricing and taxation, other political,
economic or diplomatic developments (including the effect of international trade discussion and disputes),
changing political conditions and international monetary and currency rate fluctuations. In addition, some
countries where we operate lack a fully independent judiciary system. This, coupled with changes in foreign
law or policy, results in a lack of legal certainty that exposes our operations to increased risks, including
increased difficulty in enforcing our agreements in those jurisdictions and increased risks of adverse actions by
local government authorities, such as expropriations.
25
Our business may be adversely affected by price controls, government-imposed limitations on production of
crude oil, bitumen, natural gas and NGLs, or the unavailability of adequate gathering, processing,
compression, transportation, and pipeline facilities and equipment for our production of crude oil, bitumen,
natural gas and NGLs.
As discussed above, our operations are subject to extensive governmental regulations. From time to time,
regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of
crude oil, bitumen, natural gas and NGL wells below actual production capacity. Because legal requirements
are frequently changed and subject to interpretation, we cannot predict whether future restrictions on our
business may be enacted or become applicable to us.
Our ability to sell and deliver the crude oil, bitumen, natural gas, NGLs and LNG that we produce also
depends on the availability, proximity, and capacity of gathering, processing, compression, transportation and
pipeline facilities and equipment, as well as any necessary diluents to prepare our crude oil, bitumen, natural
gas, NGLs and LNG for transport. The facilities, equipment and diluents we rely on may be temporarily
unavailable to us due to market conditions, extreme weather events, regulatory reasons, mechanical reasons or
other factors or conditions, many of which are beyond our control. In addition, in certain newer plays, the
capacity of necessary facilities, equipment and diluents may not be sufficient to accommodate production from
existing and new wells, and construction and permitting delays, permitting costs and regulatory or other
constraints could limit or delay the construction, manufacture or other acquisition of new facilities and
equipment. If any facilities, equipment or diluents, or any of the transportation methods and channels that we
rely on become unavailable for any period of time, we may incur increased costs to transport our crude oil,
bitumen, natural gas, NGLs and LNG for sale or we may be forced to curtail our production of crude oil,
bitumen, natural gas or NGLs.
Our investments in joint ventures decrease our ability to manage risk.
We conduct many of our operations through joint ventures in which we may share control with our joint
venture partners. There is a risk our joint venture participants may at any time have economic, business or
legal interests or goals that are inconsistent with those of the joint venture or us, or our joint venture partners
may be unable to meet their economic or other obligations and we may be required to fulfill those obligations
alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks
associated with any operations, acquisitions or dispositions could have a material adverse effect on the
financial condition or results of operations of our joint ventures and, in turn, our business and operations.
We may not be able to successfully complete any disposition we elect to pursue.
From time to time, we may seek to divest portions of our business or investments that are not important to our
ongoing strategic objectives. Any dispositions we undertake may involve numerous risks and uncertainties,
any of which could adversely affect our results of operations or financial condition. In particular, we may not
be able to successfully complete any disposition on a timeline or on terms acceptable to us, if at all, whether
due to market conditions, regulatory challenges or other concerns. In addition, the reinvestment of capital
from disposition proceeds may not ultimately yield investment returns in line with our internal or external
expectations. Any dispositions we pursue may also result in disruption to other parts of our business,
including through the diversion of resources and management attention from our ongoing business and other
strategic matters, or through the disruption of relationships with our employees and key vendors. Further, in
connection with any disposition, we may enter into transition services agreements or undertake indemnity or
other obligations that may result in additional expenses for us. We may also be required under applicable
accounting rules to recognize impairments associated with any disposition we pursue, whether or not
completed.
As part of our disposition strategy, on May 17, 2017, we completed the sale of our 50 percent nonoperated
interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy.
Consideration for the transaction included 208 million Cenovus Energy common shares. We may not be able
to liquidate the shares issued to us by Cenovus Energy at prices we deem acceptable, or at all.
26
Our operations present hazards and risks that require significant and continuous oversight.
The scope and nature of our operations present a variety of significant hazards and risks, including operational
hazards and risks such as explosions, fires, crude oil spills, severe weather, geological events, labor disputes,
armed hostilities, terrorist attacks, sabotage, civil unrest or cyber attacks. Our operations may also be
adversely affected by unavailability, interruptions or accidents involving services or infrastructure required to
develop, produce, process or transport our production, such as contract labor, drilling rigs, pipelines, railcars,
tankers, barges or other infrastructure. Our operations are subject to the additional hazards of pollution,
releases of toxic gas and other environmental hazards and risks. Offshore activities may pose incrementally
greater risks because of complex subsurface conditions such as higher reservoir pressures, water depths and
metocean conditions. All such hazards could result in loss of human life, significant property and equipment
damage, environmental pollution, impairment of operations, substantial losses to us and damage to our
reputation. Further, our business and operations may be disrupted if we do not respond, or are perceived not to
respond, in an appropriate manner to any of these hazards and risks or any other major crisis or if we are
unable to efficiently restore or replace affected operational components and capacity.
Our technologies, systems and networks may be subject to cyber attacks.
Our business, like others within the oil and gas industry, has become increasingly dependent on digital
technologies, some of which are managed by third-party service providers on whom we rely to help us collect,
host or process information. Among other activities, we rely on digital technology to estimate oil and gas
reserves, process and record financial and operating data, analyze seismic and drilling information and
communicate with employees and third parties. As a result, we face various cyber security threats such as
attempts to gain unauthorized access to, or control of, sensitive information about our operations and our
employees, attempts to render our data or systems (or those of third parties with whom we do business)
corrupted or unusable, threats to the security of our facilities and infrastructure as well as those of third parties
with whom we do business and attempted cyber terrorism.
In addition, computers control oil and gas production, processing equipment and distribution systems globally
and are necessary to deliver our production to market. A disruption, failure or a cyber breach of these
operating systems, or of the networks and infrastructure on which they rely, many of which are not owned or
operated by us, could damage critical production, distribution or storage assets, delay or prevent delivery to
markets or make it difficult or impossible to accurately account for production and settle transactions.
Although we have experienced occasional breaches of our cyber security, none of these breaches have had a
material effect on our business, operations or reputation. As cyber attacks continue to evolve, we must
continually expend additional resources to continue to modify or enhance our protective measures or to
investigate and remediate any vulnerabilities detected. Our implementation of various procedures and controls
to monitor and mitigate security threats and to increase security for our information, facilities and
infrastructure may result in increased costs. Despite our ongoing investments in security resources, talent and
business practices, we are unable to assure that any security measures will be effective.
If our systems and infrastructure were to be breached, damaged or disrupted, we could be subject to serious
negative consequences, including disruption of our operations, damage to our reputation, a loss of counterparty
trust, reimbursement or other costs, increased compliance costs, significant litigation exposure and legal
liability or regulatory fines, penalties or intervention. Any of these could materially and adversely affect our
business, results of operations or financial condition. Although we have business continuity plans in place, our
operations may be adversely affected by significant and widespread disruption to our systems and
infrastructure that support our business. While we continue to evolve and modify our business continuity
plans, there can be no assurance that they will be effective in avoiding disruption and business impacts.
Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain
adequate coverage may increase for us in the future.
27
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, including those involving governmental
authorities under federal, state and local laws regulating the discharge of materials into the environment for
this reporting period. The following proceedings include those matters that arose during the fourth quarter of
2019, as well as matters previously reported in our 2018 Form 10-K and our first-, second- and third-quarter
2019 Form 10-Qs that were not resolved prior to the fourth quarter of 2019. Material developments to the
previously reported matters have been included in the descriptions below. While it is not possible to
accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings
were to be decided adversely to ConocoPhillips, we expect there would be no material effect on our
consolidated financial position. Nevertheless, such proceedings are reported pursuant to SEC regulations.
On April 30, 2012, the separation of our downstream business was completed, creating two independent
energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an
Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and
established procedures for handling claims subject to indemnification and related matters, such as legal
proceedings. We have included matters where we remain or have subsequently become a party to a
proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters
to result in a net claim against us.
Matters Previously Reported—Phillips 66
In May 2012, the Illinois Attorney General's office filed and notified ConocoPhillips of a complaint with
respect to operations at the Phillips 66 WRB Wood River Refinery alleging violations of the Illinois
groundwater standards and a third-party's hazardous waste permit. The complaint seeks remediation of area
groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures;
additional spill reporting; and yet-to-be specified amounts for fines and penalties.
Matters Previously Reported—ConocoPhillips
On June 28, 2018, the Texas Commission on Environmental Quality issued a Proposed Agreed Order to
ConocoPhillips Company to resolve alleged violations of the Texas Health & Safety Code and/or Commission
Rules occurring in 2015 through 2017 at a formerly owned gas injection plant in Howard County, Texas. In
November of 2019, the company concluded this matter by entering into an Agreed Order with the agency and
paying an administrative penalty of $120,014.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
28
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Name
Position Held
Catherine A. Brooks
Vice President and Controller
William L. Bullock, Jr. President, Asia Pacific & Middle East
Ellen R. DeSanctis
Senior Vice President, Corporate Relations
Matt J. Fox
Executive Vice President and Chief Operating Officer
Michael D. Hatfield
President, Alaska, Canada and Europe
Ryan M. Lance
Chairman of the Board of Directors and Chief Executive Officer
Andrew D. Lundquist
Senior Vice President, Government Affairs
Dominic E. Macklon
President, Lower 48
Kelly B. Rose
Senior Vice President, Legal, General Counsel and Corporate Secretary
Don E. Wallette, Jr.
Executive Vice President and Chief Financial Officer
Age*
54
55
63
59
53
57
59
50
53
61
*On February 15, 2020.
There are no family relationships among any of the officers named above. Each officer of the company is
elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as
appropriate. Each officer of the company holds office from the date of election until the first meeting of the
directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the
next annual meeting is May 12, 2020. Set forth below is information about the executive officers.
Catherine A. Brooks was appointed Vice President and Controller as of January 1, 2019, having previously
served as General Auditor since August 2018. Prior to serving as General Auditor, she was Assistant
Controller from February 2016 to August 2018. She became Manager, Finance & Performance Analysis in
April 2014 and served in that role until February 2016. Ms. Brooks previously held the position of Manager,
External Reporting from May 2010 to April 2014.
William L. Bullock, Jr. was appointed President, Asia Pacific & Middle East as of April 1, 2015, having
previously served as Vice President, Corporate Planning & Development since May 2012.
Ellen R. DeSanctis was appointed Senior Vice President, Corporate Relations as of January 1, 2019, having
previously served as Vice President, Investor Relations and Communications since May 2012. Prior to that,
she was employed by Petrohawk Energy Corp. where she served as Senior Vice President, Corporate
Communications since 2010.
Matt J. Fox was appointed Executive Vice President and Chief Operating Officer as of January 1, 2019,
having previously served as Executive Vice President, Strategy, Exploration and Technology since April 2016
and Executive Vice President, Exploration and Production, from 2012 to 2016. Prior to that, he was employed
by Nexen, Inc., where he served as Executive Vice President, International since 2010.
Michael D. Hatfield was appointed President, Alaska, Canada and Europe as of June 3, 2018, having
previously served as President, Canada since October 2016. Prior to that, he served as Vice President, Health,
Safety and Environment from December 2015 to October 2016. Mr. Hatfield became Vice President, Cost
Optimization in March 2015 and served in that role until December 2015. Mr. Hatfield previously held the
position of Vice President, Rockies Business Unit from March 2013 to March 2015.
Ryan M. Lance was appointed Chairman of the Board of Directors and Chief Executive Officer in May 2012,
having previously served as Senior Vice President, Exploration and Production—International since May
2009.
Andrew D. Lundquist was appointed Senior Vice President, Government Affairs in 2013. Prior to that, he
served as managing partner of BlueWater Strategies LLC, since 2002.
29
Dominic E. Macklon was appointed President, Lower 48 as of June 1, 2018, having previously served as Vice
President, Corporate Planning & Development since January 2017. Prior to that, he served as President, U.K.
from September 2015 to January 2017. Mr. Macklon previously served as Senior Vice President, Oil Sands
from July 2012 to September 2015.
Kelly B. Rose was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary in
September 2018. Prior to that, she was a senior partner in the Houston office of an international law firm,
Baker Botts L.L.P., where she counseled clients on corporate and securities matters. She began her career at
the firm in 1991.
Don E. Wallette, Jr. was appointed Executive Vice President and Chief Financial Officer on January 1, 2019,
having previously served as Executive Vice President, Finance, Commercial and Chief Financial Officer since
April 2016 and as Executive Vice President, Commercial, Business Development and Corporate Planning
from 2012 to 2016. Prior to that, he served as President, Asia Pacific from 2010 to 2012 and President,
Russia/Caspian from 2006 to 2010.
30
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”
Cash Dividends Per Share
First
Second
Third
Fourth
Dividends
2019
$
0.305
0.305
0.305
0.420
2018
0.285
0.285
0.285
0.305
Number of Stockholders of Record at January 31, 2020*
*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency
listing.
41,821
The declaration of dividends is subject to the discretion of our Board of Directors, and may be affected by
various factors, including our future earnings, financial condition, capital requirements, levels of indebtedness,
credit ratings and other considerations our Board of Directors deems relevant. Our Board of Directors has
adopted a quarterly dividend declaration policy providing that the declaration of any dividends will be
determined quarterly by the Board of Directors taking into account such factors as our business model,
prevailing business conditions and our financial results and capital requirements, without a predetermined
annual net income payout ratio.
On February 1, 2018, we announced that our Board of Directors approved an increase in the quarterly dividend
to $0.285 per share, compared with the previous quarterly dividend of $0.265 per share.
On October 5, 2018, we announced that our Board of Directors approved an increase in the quarterly dividend
to $0.305 per share, compared with the previous quarterly dividend of $0.285 per share.
On October 7, 2019, we announced that our Board of Directors approved an increase in the quarterly dividend
to $0.42 per share, compared with the previous quarterly dividend of $0.305 per share.
31
Issuer Purchases of Equity Securities
Total Number of
Shares Purchased *
Average
Price Paid
Per Share
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
Millions of Dollars
Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under the
Plans or Programs
4,844,970
4,020,276
3,943,490
12,808,736
$
$
55.54
58.20
62.31
58.46
$
4,844,970
4,020,276
3,943,490
12,808,736
5,855
5,621
5,375
Period
October 1-31, 2019
November 1-30, 2019
December 1-31, 2019
*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.
In late 2016, we initiated our current share repurchase program. As of December 31, 2019, we had announced
a total authorization to repurchase $15 billion of our common stock. We repurchased $3 billion in 2017, $3
billion in 2018 and $3.5 billion in 2019. Of the remaining authorization, we expect to repurchase $3 billion in
2020. In February 2020, we announced that the Board of Directors approved an increase to our repurchase
authorization from $15 billion to $25 billion, to support our plan for future share repurchases. Acquisitions for
the share repurchase program are made at management’s discretion, at prevailing prices, subject to market
conditions and other factors. Except as limited by applicable legal requirements, repurchases may be
increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the
plan are held as treasury shares. See Risk Factors “Our ability to declare and pay dividends and repurchase
shares is subject to certain considerations.”
32
Stock Performance Graph
The following graph shows the cumulative total shareholder return (TSR) for ConocoPhillips’ common stock
in each of the five years from December 31, 2014, to December 31, 2019. The graph also compares the
cumulative total returns for the same five-year period with the S&P 500 Index, the performance peer group
used in the prior fiscal year (the “Prior Peer Group”) and a new performance peer group for the current fiscal
year (the “New Peer Group”). The Prior Peer Group consists of BP, Chevron, ExxonMobil, Royal Dutch
Shell, Total, Apache, Devon, Marathon Oil Corporation and Occidental, weighted according to the respective
peer’s stock market capitalization at the beginning of each annual period. For the purpose of aligning to
performance peers with similar complexities and portfolios, the New Peer Group excludes BP, Royal Dutch
Shell, and Total, and includes Noble Energy, Hess, and EOG Resources. For the 2018 Stock Performance
Graph, Anadarko was also presented within the Prior Peer Group. However, due to Anadarko’s acquisition by
Occidental completed in 2019, Anadarko’s performance has been excluded from all five years of the Prior Peer
Group performance. The comparison assumes $100 was invested on December 31, 2014, in ConocoPhillips
stock, the S&P 500 Index and ConocoPhillips’ peer groups and assumes that all dividends were reinvested.
The cumulative total returns of the peer group companies' common stock do not include the cumulative total
return of ConocoPhillips’ common stock. The stock price performance included in this graph is not
necessarily indicative of future stock price performance.
*Prior Peer Group: BP; Chevron; ExxonMobil; Royal Dutch Shell; Total; Apache; Devon, Marathon Oil Corporation; Occidental.
**New Peer Group: Chevron; ExxonMobil; Apache; Devon; EOG Resources; Hess; Marathon Oil Corporation; Noble Energy; Occidental.
33
Item 6. SELECTED FINANCIAL DATA
Sales and other operating revenues
Net income (loss)
Net income (loss) attributable to
ConocoPhillips
Per common share
Basic
Diluted
Total assets
Long-term debt
Cash dividends declared per common share
Millions of Dollars Except Per Share Amounts
2019
2018
2017
2016
2015
$
32,567
7,257
7,189
36,417
6,305
6,257
29,106
(793)
(855)
23,693
(3,559)
(3,615)
29,564
(4,371)
(4,428)
6.43
6.40
70,514
14,790
1.34
5.36
5.32
69,980
14,856
1.16
(0.70)
(0.70)
73,362
17,128
1.06
(2.91)
(2.91)
89,772
26,186
1.00
(3.58)
(3.58)
97,484
23,453
2.94
In 2019, we disposed of two ConocoPhillips U.K. subsidiaries for proceeds of $2.2 billion after interest and
customary adjustments.
In 2017, we disposed of assets for consideration of approximately $16 billion including our 50 percent
nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, and
our interests in the San Juan Basin.
These factors impact the comparability of historical information.
See Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Notes to
Consolidated Financial Statements for a discussion of factors that will enhance an understanding of this data.
34
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of
significant trends that may affect future performance. It should be read in conjunction with the financial
statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains
forward-looking statements including, without limitation, statements relating to the company’s plans,
strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of
the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,”
“budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,”
“would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target”
and similar expressions identify forward-looking statements. The company does not undertake to update,
revise or correct any of the forward-looking information unless required to do so under the federal securities
laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the
company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE
‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,”
beginning on page 70.
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is an independent E&P company with operations and activities in 17 countries. Our diverse,
low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional
assets in North America, Europe, Asia and Australia; LNG developments; oil sands in Canada; and an
inventory of global conventional and unconventional exploration prospects. Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately 10,400 people worldwide and had total assets of
$71 billion.
Overview
Global oil prices continued to be volatile in 2019. Optimism about worldwide economic growth during the
first quarter turned to pessimism in the second quarter as trade disputes dampened growth forecasts. At the
end of the second quarter, geopolitical tensions in the Middle East, threatening the safe passage of supertankers
carrying crude oil through the Persian Gulf, revived oil prices. Worldwide economic growth concerns returned
in the third quarter to depress prices, only to be reversed again by geopolitical tensions in the Middle East, as
oilfield infrastructure in Saudi Arabia was attacked, temporarily disrupting approximately five percent of the
world’s oil supply. Production was restored relatively quickly, and prices settled in the fourth quarter. Brent
crude averaged $64 per barrel in 2019, down nine percent from the prior year. Our business strategy
anticipates prices will remain volatile and is designed to be resilient in lower price environments, while
retaining upside during periods of higher prices. Portfolio diversification and optimization, a strong balance
sheet and disciplined capital investment have positioned our company to navigate through volatile energy
cycles.
Our value proposition principles, namely, to focus on financial returns, maintain a strong balance sheet, deliver
compelling returns of capital, and expand cash flow through disciplined capital investments, are being
executed in accordance with our priorities for allocating cash flows from the business. These priorities are:
invest capital to sustain production and pay our existing dividend; grow our existing dividend; maintain debt at
a level we believe is sufficient to maintain a strong investment grade credit rating through price cycles; allocate
greater than 30 percent of our net cash provided by operating activities to share repurchases and dividends;
and, invest capital in a disciplined fashion to grow our cash from operations. We believe our commitment to
our value proposition, as evidenced by the results discussed below, positions us for success in an environment
of price uncertainty and ongoing volatility.
35
In 2019, we successfully delivered on our priorities. We achieved production growth of five percent on a total
BOE basis compared with the prior year, with higher value oil volumes growing eight percent. Cash provided
by operating activities of $11.1 billion exceeded capital expenditures and investments of $6.6 billion. After
repurchasing $3.5 billion of our common stock and paying $1.5 billion of dividends to shareholders, we ended
the year with cash, cash equivalents and restricted cash totaling $5.4 billion and $3.0 billion of short-term
investments. In October, we announced an increase to our quarterly dividend of 38 percent to $0.42 per share
and announced planned 2020 share buybacks of $3 billion.
In February 2020, we announced 2020 operating plan capital of $6.5 billion to $6.7 billion. The plan includes
funding for ongoing development drilling programs, major projects, exploration and appraisal activities, as
well as base maintenance. Capital spend is expected to be higher in the first quarter largely from winter
construction and exploration and appraisal drilling in Alaska. This guidance does not include capital for
acquisitions.
Key Operating and Financial Summary
Significant items during 2019 included the following:
• Net cash provided by operating activities was $11.1 billion and exceeded capital expenditures and
investments of $6.6 billion.
• Repurchased $3.5 billion of shares and paid $1.5 billion in dividends, representing 45 percent of net cash
provided by operating activities.
Increased the quarterly dividend by 38 percent to $0.42 per share.
•
• Achieved 100 percent total reserve replacement and 117 percent organic replacement.
• Underlying production, which excludes Libya and the net volume impact from closed dispositions and
•
acquisitions of 51 MBOED in 2019 and 47 MBOED in 2018, grew 5 percent.
Increased production from the Lower 48 Big 3 unconventionals—Eagle Ford, Bakken and Permian
Unconventional—by 22 percent year-over-year.
• Executed successful Alaska appraisal program; conducted appraisal drilling and commissioned
infrastructure at Montney in Canada.
• Completed Lower 48, Alaska and Argentina acquisitions; awarded a 20-year extension of the Indonesia
Corridor Block PSC, with new terms.
• Generated $3 billion in disposition proceeds; entered into agreements to sell Australia-West assets for $1.4
billion and Niobrara for $0.4 billion, both subject to customary closing adjustments, as well as regulatory
and other approvals.
• Reduced asset retirement obligations and accrued environmental costs by $2.3 billion, primarily due to
closed and pending dispositions.
• Ended the year with cash, cash equivalents and restricted cash totaling $5.4 billion and short-term
investments of $3.0 billion.
• Recognized a $296 million after-tax impairment related to the sale of our Niobrara interests in the Lower
48 segment.
• Discontinued exploration activities in the Central Louisiana Austin Chalk trend and recognized $197
million after-tax in leasehold impairment and dry hole expenses.
Operationally, we remain focused on safely executing our operating plan and maintaining capital and cost
discipline. Production of 1,348 MBOED increased 5 percent or 65 MBOED in 2019 compared with 2018.
Production, excluding Libya, of 1,305 MBOED increased 5 percent or 63 MBOED. Underlying production,
which excludes Libya and the net volume impact from closed dispositions and acquisitions of 51 MBOED in
2019 and 47 MBOED in 2018, is used to measure our ability to grow production organically. Our underlying
production grew 5 percent in 2019 to 1,254 MBOED from 1,195 MBOED in 2018.
On September 30, 2019, we completed the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P
Limited for proceeds of $2.2 billion after interest and customary adjustments. In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax gain associated with this transaction. Together the subsidiaries
36
sold our indirectly held exploration and production assets in the U.K., including $1.8 billion of ARO.
Annualized average production associated with the U.K. assets sold was 50 MBOED in 2019. Reserves
associated with the U.K. assets sold were 84 MMBOE at the time of disposition. Results of operations for the
U.K. are reported within our Europe and North Africa segment.
In the second quarter of 2019, we completed the sale of our 30 percent interest in the Greater Sunrise Fields to
the government of Timor-Leste for $350 million and recognized an after-tax gain of $52 million. No
production or reserve impacts were associated with the sale. The Greater Sunrise Fields were included in our
Asia Pacific and Middle East segment.
In October 2019, we entered into an agreement to sell the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary adjustments, with an effective date of January 1, 2019.
In addition, we will receive a payment of $75 million upon final investment decision of the Barossa
development project. These subsidiaries hold our 37.5 percent interest in the Barossa Project and Caldita
Field, our 56.9 percent interest in the Darwin LNG Facility and Bayu-Undan Field, our 40 percent interest in
the Greater Poseidon Fields, and our 50 percent interest in the Athena Field. This transaction is expected to be
completed in the first quarter of 2020, subject to regulatory approvals and the satisfaction of other specific
conditions precedent. In 2019, production associated with the Australia-West assets to be sold was 48
MBOED. Year-end 2019 reserves associated with these assets were 17 MMBOE. We will retain our 37.5
percent interest in the Australia Pacific LNG project and operatorship of that project’s LNG facility. Results
of operations for the subsidiaries to be sold are reported within our Asia Pacific and Middle East segment.
In the fourth quarter of 2019, we signed an agreement to sell our interests in the Niobrara shale play for $380
million, plus customary adjustments, and overriding royalty interests in certain future wells. We recorded an
after-tax impairment of $296 million in the fourth quarter of 2019 to reduce the carrying value to fair value. In
2019, production from Niobrara was 11 MBOED. Year-end 2019 reserves associated with the Niobrara assets
to be sold were 14 MMBOE. This transaction is subject to regulatory approval and other conditions precedent
and is expected to close in the first quarter of 2020. The Niobrara results of operations are reported within our
Lower 48 segment.
For more information regarding the accounting impacts of these transactions, see Note 5—Asset Acquisitions
and Dispositions, in the Notes to Consolidated Financial Statements.
Business Environment
Brent crude oil prices averaged $64 per barrel in 2019, ranging from a low of $53 per barrel in January to a
high of almost $75 per barrel in April. The energy industry has periodically experienced this type of volatility
due to fluctuating supply-and-demand conditions and such volatility may persist for the foreseeable future.
Commodity prices are the most significant factor impacting our profitability and related reinvestment of
operating cash flows into our business. Our strategy is to create value through price cycles by delivering on
the foundational principles that underpin our value proposition; focus on financial returns through cash flow
expansion, maintain balance sheet strength and deliver peer-leading distributions.
Operational and Financial Factors Affecting Profitability
The focus areas we believe will drive our success through the price cycles include:
• Maintain a relentless focus on safety and environmental stewardship. Safety and environmental
stewardship, including the operating integrity of our assets, remain our highest priorities, and we are
committed to protecting the health and safety of everyone who has a role in our operations and the
communities in which we operate. We strive to conduct our business with respect and care for both
the local and global environment and systematically manage risk to drive sustainable business growth.
Demonstrating our commitment to sustainability and environmental stewardship, on November 2017,
we announced our intention to target a 5 to 15 percent reduction in our GHG emission
intensity by 2030. In December 2018, we became a founding member of the Climate Leadership
Council (CLC), an international policy institute founded in collaboration with business and
37
environmental interests to develop a carbon dividend plan. Participation in the CLC provides another
opportunity for ongoing dialogue about carbon pricing and framing the issues in alignment with our
public policy principles. We also belong to and fund Americans For Carbon Dividends, the education
and advocacy branch of the CLC. In early 2019, we issued our first stand-alone Climate-related Risk
Report and incorporated this into our website during our annual Sustainability Report update. Our
sustainability efforts continued through 2019 with a focus on advancing our action plans for climate
change, biodiversity, water and human rights. We are committed to building a learning organization
using human performance principles as we relentlessly pursue improved HSE and operational
performance.
• Focus on financial returns. This is a core principle of our value proposition. Our goal is to achieve
strong financial returns by exercising capital discipline, controlling our costs, and continually
optimizing our portfolio.
o Maintain capital allocation discipline. We participate in a commodity price-driven and
capital-intensive industry, with varying lead times from when an investment decision is made
to the time an asset is operational and generates cash flow. As a result, we must invest
significant capital dollars to explore for new oil and gas fields, develop newly discovered
fields, maintain existing fields, and construct pipelines and LNG facilities. We allocate
capital across a geographically diverse, low cost of supply resource base, which combined
with legacy assets results in low production decline. Cost of supply is the WTI equivalent
price that generates a 10 percent after-tax return on a point-forward and fully burdened basis.
Fully burdened includes capital infrastructure, foreign exchange, price related inflation and
G&A. In setting our capital plans, we exercise a rigorous approach that evaluates projects
using this cost of supply criteria, which should lead to value maximization and cash flow
expansion using an optimized investment pace, not production growth for growth’s sake.
Additional capital may be allocated toward growth, but discipline will be maintained. Our
cash allocation priorities call for the investment of sufficient capital to sustain production and
pay the existing dividend.
In February 2020, we announced 2020 operating plan capital of $6.5 billion to $6.7 billion.
The plan includes funding for ongoing development drilling programs, major projects,
exploration and appraisal activities, as well as base maintenance. Capital spend is expected to
be higher in the first quarter largely from winter construction and exploration and appraisal
drilling in Alaska. This guidance does not include capital for acquisitions.
o Control costs and expenses. Controlling operating and overhead costs, without compromising
safety and environmental stewardship, is a high priority. We monitor these costs using
various methodologies that are reported to senior management monthly, on both an absolute-
dollar basis and a per-unit basis. Managing operating and overhead costs is critical to
maintaining a competitive position in our industry, particularly in a low commodity price
environment. The ability to control our operating and overhead costs impacts our ability to
deliver strong cash from operations. In 2019, our production and operating expenses were
two percent higher than 2018, primarily due to costs associated with higher production
volumes, which grew five percent during the same period.
o Optimize our portfolio. We continue to optimize our asset portfolio to focus on low cost of
supply assets that support our strategy. In 2019, we continued to dispose of or market certain
non-core assets, including the U.K., Australia-West and our Niobrara assets in the Lower 48.
Additions to the portfolio were made in the Lower 48 with bolt-on interests and acreage
acquisitions, in Alaska with the Nuna discovery acreage acquisition, and internationally with
entrance into Argentina’s Neuquén and Austral Basins. We will continue to evaluate our
assets to determine whether they compete for capital within our portfolio and will optimize
the portfolio as necessary, directing capital towards the most competitive investments.
38
• Maintain balance sheet strength. We believe balance sheet strength is critical in a cyclical business
such as ours. Our strong operating performance buffered by a solid balance sheet enables us to deliver
on our priorities through the price cycles. Our priorities include execution of our development plans,
maintaining a growing dividend, and repurchasing shares on a dollar cost average basis.
• Return value to shareholders. We believe in delivering value to our shareholders via a growing,
sustainable dividend supplemented by share repurchases. In 2019, we paid dividends on our common
stock of approximately $1.5 billion and repurchased $3.5 billion of our common stock. Combined,
our dividend and repurchases represented 45 percent of our net cash provided by operating activities.
Since we initiated our current share repurchase program in late 2016, we have repurchased $9.6 billion
of shares. Additionally, as of December 31, 2019, $5.4 billion of repurchase authority remained of the
$15 billion share repurchase program our Board of Directors had authorized. In February 2020, we
announced that the Board of Directors approved an increase to our repurchase authorization from $15
billion to $25 billion, to support our plan for future share repurchases. Whether we undertake these
additional repurchases is ultimately subject to numerous considerations, including market conditions
and other factors. See Risk Factors “Our ability to declare and pay dividends and repurchase shares is
subject to certain considerations.”
In October 2019, we announced that our Board of Directors approved an increase to our quarterly
dividend of 38 percent to $0.42 per share.
• Add to our proved reserve base. We primarily add to our proved reserve base in three ways:
o Successful exploration, exploitation and development of new and existing fields.
o Application of new technologies and processes to improve recovery from existing fields.
o Purchases of increased interests in existing fields and bolt-on acquisitions.
Proved reserve estimates require economic production based on historical 12-month, first-of-month,
average prices and current costs. Therefore, our proved reserves generally increase as prices rise and
decrease as prices decline. Reserve replacement represents the net change in proved reserves, net of
production, divided by our current year production, as shown in our supplemental reserve table
disclosures. In 2019, our reserve replacement, which included a net decrease of 0.1 billion BOE from
sales and purchases, was 100 percent. Increased crude oil reserves accounted for approximately 55
percent of the total change in reserves. Our organic reserve replacement, which excludes the impact of
sales and purchases, was 117 percent in 2019. Approximately 50 percent of organic reserve additions
were from Lower 48 unconventional assets. The remaining additions were evenly distributed across
the other operating segments.
In the five years ended December 31, 2019, our reserve replacement was negative 34 percent,
reflecting the impact of asset dispositions and lower prices during that period. Our organic reserve
replacement during the five years ended December 31, 2019, which excludes a decrease of 2.0 billion
BOE related to sales and purchases, was 40 percent, reflecting development activities as well as lower
prices during that period.
Historically, our reserve replacement has varied considerably year to year contingent upon the timing
of major projects which may have long lead times between capital investment and production. In the
last several years, more of our capital has been allocated to short cycle time, onshore, unconventional
plays. Accordingly, we believe our recent success in replacing reserves can be viewed on a trailing
three-year basis.
In the three years ended December 31, 2019, our reserve replacement was 23 percent, reflecting the
impact of asset dispositions during that period. Our organic reserve replacement during the three
years ended December 31, 2019, which excludes a decrease of 1.8 billion BOE related to sales and
purchases, was 143 percent, reflecting reserve additions from development activities.
39
Access to additional resources may become increasingly difficult as commodity prices can make
projects uneconomic or unattractive. In addition, prohibition of direct investment in some nations,
national fiscal terms, political instability, competition from national oil companies, and lack of access
to high-potential areas due to environmental or other regulation may negatively impact our ability to
increase our reserve base. As such, the timing and level at which we add to our reserve base may, or
may not, allow us to replace our production over subsequent years.
• Apply technical capability. We leverage our knowledge and technology to create value and safely
deliver on our plans. Technical strength is part of our heritage and allows us to economically convert
additional resources to reserves, achieve greater operating efficiencies and reduce our environmental
impact. Companywide, we continue to evaluate potential solutions to leverage knowledge of
technological successes across our operations.
We have embraced the digital transformation and are using digital innovations to work and operate
more efficiently. Predictive analytics have been adopted in our operations and planning process.
Artificial intelligence, machine learning and deep learning are being used for seismic advancements.
• Attract, develop and retain a talented work force. We strive to attract, develop and retain individuals
with the knowledge and skills to implement our business strategy and who support our values and
ethics. We offer university internships across multiple disciplines to attract the best early career
talent. We also recruit experienced hires to fill critical skills and maintain a broad range of expertise
and experience. We promote continued learning, development and technical training through
structured development programs designed to enhance the technical and functional skills of our
employees.
Other Factors Affecting Profitability
Other significant factors that can affect our profitability include:
• Energy commodity prices. Our earnings and operating cash flows generally correlate with industry
price levels for crude oil and natural gas. Industry price levels are subject to factors external to the
company and over which we have no control, including but not limited to global economic health,
supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by OPEC,
environmental laws, tax regulations, governmental policies and weather-related disruptions. The
following graph depicts the average benchmark prices for WTI crude oil, Brent crude oil and U.S.
Henry Hub natural gas:
40
Brent crude oil prices averaged $64.30 per barrel in 2019, a decrease of 9 percent compared with
$71.04 per barrel in 2018. Similarly, WTI crude oil prices decreased 12 percent from $64.92 per
barrel in 2018 to $57.02 per barrel in 2019. Crude oil prices weakened year over year primarily due to
ample global supplies and a decelerating global economy.
Henry Hub natural gas price averages decreased 15 percent from $3.09 per MMBTU in 2018 to $2.63
per MMBTU in 2019. Natural gas prices weakened in 2019 versus the prior year due to strong
production, while demand growth was dampened by mild weather.
Our realized NGL prices decreased 34 percent from $30.48 per barrel in 2018 to $20.09 per barrel in
2019. NGL prices weakened year over year due to strong supply growth with only moderate demand
growth.
Our realized bitumen price increased 42 percent from $22.29 per barrel in 2018 to $31.72 per barrel in
2019. Curtailment orders imposed by the Alberta Government, which limited production from the
province starting January 2019, provided strength to the WCS differential to WTI at Hardisty. We
continue to optimize bitumen price realizations through the utilization of downstream transportation
solutions and implementation of alternate blend capability which results in lower diluent costs.
Our worldwide annual average realized price decreased 9 percent from $53.88 per BOE in 2018 to
$48.78 per BOE in 2019 due to lower realized oil, natural gas and NGL prices.
North America’s energy supply landscape has been transformed from one of resource scarcity to one
of abundance. In recent years, the use of hydraulic fracturing and horizontal drilling in
unconventional formations has led to increased industry actual and forecasted crude oil and natural
gas production in the U.S. Although providing significant short- and long-term growth opportunities
for our company, the increased abundance of crude oil and natural gas due to development of
unconventional plays could also have adverse financial implications to us, including: an extended
period of low commodity prices; production curtailments; and delay of plans to develop areas such as
unconventional fields. Should one or more of these events occur, our revenues would be reduced, and
additional asset impairments might be possible.
•
Impairments. We participate in a capital-intensive industry. At times, our PP&E and investments
become impaired when, for example, commodity prices decline significantly for long periods of time,
our reserve estimates are revised downward, or a decision to dispose of an asset leads to a write-down
to its fair value. We may also invest large amounts of money in exploration which, if exploratory
drilling proves unsuccessful, could lead to a material impairment of leasehold values. As we optimize
our assets in the future, it is reasonably possible we may incur future losses upon sale or impairment
charges to long-lived assets used in operations, investments in nonconsolidated entities accounted for
under the equity method, and unproved properties. A sustained decline in the current and long-term
outlook on gas price could affect the carrying value of certain Lower 48 non-core gas assets and it is
reasonably possible this could result in a future non-cash impairment. For additional information on
our impairments in 2019, 2018 and 2017, see Note 9—Impairments, in the Notes to Consolidated
Financial Statements.
• Effective tax rate. Our operations are in countries with different tax rates and fiscal structures.
Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall
effective tax rate can vary significantly between periods based on the “mix” of before-tax earnings
within our global operations.
• Fiscal and regulatory environment. Our operations can be affected by changing economic, regulatory
and political environments in the various countries in which we operate, including the U.S. Civil
unrest or strained relationships with governments may impact our operations or investments. These
changing environments could negatively impact our results of operations, and further changes to
41
increase government fiscal take could have a negative impact on future operations. Our management
carefully considers the fiscal and regulatory environment when evaluating projects or determining the
levels and locations of our activity.
Outlook
Full-year 2020 production is expected to be 1,230 MBOED to 1,270 MBOED, including the impact of a recent
third-party pipeline outage on the Kebabangan Field in Malaysia. First-quarter 2020 production is expected to
be 1,240 MBOED to 1,280 MBOED. Production guidance for 2020 excludes Libya.
Operating Segments
We manage our operations through six operating segments, which are primarily defined by geographic region:
Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International.
Corporate and Other represents costs not directly associated with an operating segment, such as most interest
expense, premiums incurred on the early retirement of debt, corporate overhead, certain technology activities,
as well as licensing revenues.
Our key performance indicators, shown in the statistical tables provided at the beginning of the operating
segment sections that follow, reflect results from our operations, including commodity prices and production.
42
RESULTS OF OPERATIONS
This section of the Form 10-K discusses year-to-year comparisons between 2019 and 2018. For discussion of
year-to-year comparisons between 2018 and 2017, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in Part II, Item 7 of our 2018 10-K.
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips by business segment follows:
Years Ended December 31
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Net income (loss) attributable to ConocoPhillips
2019 vs. 2018
Millions of Dollars
2019
2018
2017
$
$
1,520
436
279
2,724
1,929
263
38
7,189
1,814
1,747
63
1,866
2,070
364
(1,667)
6,257
1,466
(2,371)
2,564
553
(1,098)
167
(2,136)
(855)
Net income attributable to ConocoPhillips increased $932 million in 2019. The increase was mainly due to:
• A $2.1 billion after-tax gain associated with the completion of the sale of two ConocoPhillips U.K.
subsidiaries to Chrysaor E&P Limited.
• An unrealized gain of $649 million after-tax on our Cenovus Energy (CVE) common shares in 2019,
as compared to a $436 million after-tax unrealized loss on those shares in 2018.
• Higher crude oil sales volumes due to growth in the Lower 48 unconventionals and from the
acquisition of incremental interests in operated assets in Alaska during the second and fourth quarters
of 2018.
• The absence of premiums on early debt retirements totaling $195 million after-tax.
• A $164 million income tax benefit related to deepwater incentive tax credits recognized for Malaysia
Block G.
• A $151 million income tax benefit related to the revaluation of deferred tax assets following
finalization of rules relating to the 2017 Tax Cuts and Jobs Act.
These increases in net income were partly offset by:
• Lower realized crude oil, natural gas and NGL prices.
• The absence of a $774 million after-tax gain on the Clair disposition in the U.K.
• A $296 million after-tax impairment related to the sale of our Lower 48 Niobrara interests.
• Lower equity in earnings of affiliates due to $120 million of impairments to equity method
investments in our Lower 48 segment and a $118 million reduction in equity earnings at QG3 in our
Asia Pacific and Middle East segment due to a deferred tax adjustment.
• Higher exploration expenses, primarily in our Lower 48 segment due to $197 million after-tax of
leasehold impairment and dry hole costs associated with our decision to discontinue exploration
activities in the Central Louisiana Austin Chalk trend.
43
Income Statement Analysis
2019 vs. 2018
Sales and other operating revenues decreased 11 percent in 2019, mainly due to lower realized crude oil,
natural gas and NGL prices, partly offset by higher sales volumes of crude oil in the Lower 48 and Alaska.
Equity in earnings of affiliates decreased $295 million in 2019, primarily due to impairments of equity method
investments in our Lower 48 segment totaling $155 million. Additionally, equity earnings decreased $118
million resultant from a deferred tax adjustment at QG3, reported in our Asia Pacific and Middle East segment.
For more information related to these items, see Note 3—Variable Interest Entities and Note 5—Asset
Acquisitions and Dispositions, in the Notes to Consolidated Financial Statements.
Gain on dispositions increased $903 million in 2019, primarily due to a $1.7 billion before-tax gain associated
with the completion of the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited. Partly
offsetting this increase, was the absence of a $715 million before-tax gain on the sale of a ConocoPhillips
subsidiary to BP in 2018, which held 16.5 percent of our 24 percent interest in the BP-operated Clair Field in
the U.K. For additional information related to these dispositions, see Note 5—Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial Statements.
Other income increased $1,185 million in 2019, primarily due to an unrealized gain of $649 million before-tax
on our CVE common shares in 2019, and the absence of a $437 million before-tax unrealized loss on those
shares in 2018. For discussion of our CVE shares, see Note 7—Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements.
Purchased commodities decreased 17 percent in 2019, primarily due to lower natural gas and crude oil prices.
Selling, general and administrative expenses increased $155 million in 2019, primarily due to higher costs
associated with compensation and benefits, including mark to market impacts of certain key employee
compensation programs, and increased facility costs.
Exploration expenses increased $374 million in 2019, primarily due to higher leasehold impairment and dry
hole costs, mainly in our Lower 48 segment, and higher exploration G&A expenses. In 2019, we recorded a
$141 million before-tax leasehold impairment expense due to our decision to discontinue exploration activities
in the Central Louisiana Austin Chalk trend and expensed $111 million of dry hole costs related to this play.
Impairments increased $378 million in 2019, mainly due to a $379 million before-tax impairment related to the
sale of our Niobrara interests in the Lower 48 segment. For additional information, see Note 5—Asset
Acquisitions and Dispositions and Note 9—Impairments, in the Notes to Consolidated Financial Statements.
Other expenses decreased $310 million in 2019, primarily due to the absence of a $206 million before-tax
expense for premiums on early debt retirements and lower pension settlement expense.
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax provision (benefit) and effective tax rate.
44
Summary Operating Statistics
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per bbl)
Natural gas liquids (per bbl)
Bitumen (per bbl)
Natural gas (per mcf)
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other
Leasehold impairment
Dry holes
2019
2018
2017
705
115
60
2,805
653
102
66
2,774
599
111
122
3,270
1,348
1,283
1,377
Dollars Per Unit
60.99
20.09
31.72
5.03
68.13
30.48
22.29
5.65
51.96
25.22
22.66
4.07
Millions of Dollars
322
221
200
743
274
56
39
369
368
136
430
934
$
$
$
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. At December 31, 2019, our operations were producing in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, China, Malaysia, Qatar and Libya.
2019 vs. 2018
Total production, including Libya, of 1,348 MBOED increased 65 MBOED or 5 percent in 2019 compared
with 2018, primarily due to:
• New wells online in the Lower 48.
• An increased interest in the Western North Slope (WNS) and Greater Kuparuk Area (GKA) of Alaska
following acquisitions closed in 2018.
• Higher production in Norway due to drilling activity and the startup of Aasta Hansteen in December
2018.
The increase in production during 2019 was partly offset by:
• Normal field decline.
• Disposition impacts from the U.K. and non-core asset sales in the Lower 48.
Production excluding Libya was 1,305 MBOED in 2019 compared with 1,242 MBOED in 2018, an increase of
63 MBOED or 5 percent. Underlying production, which excludes Libya and the net volume impact from
closed dispositions and acquisitions of 51 MBOED in 2019 and 47 MBOED in 2018, is used to measure our
ability to grow production organically. Our underlying production grew 5 percent to 1,254 MBOED in 2019
from 1,195 MBOED in 2018.
45
Alaska
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
1,520
1,814
1,466
2019
2018
2017
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per bbl)
Natural gas (per mcf)
202
15
7
218
171
14
6
186
167
14
7
182
$
64.12
3.19
70.86
2.48
53.33
2.72
The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas.
In 2019, Alaska contributed 25 percent of our worldwide liquids production and less than 1 percent of our
natural gas production.
2019 vs. 2018
Alaska reported earnings of $1,520 million in 2019, compared with earnings of $1,814 million in 2018. The
decrease in earnings was mainly due to lower realized crude oil prices and higher production and operating and
DD&A expenses associated with incremental volumes from acquisitions completed during 2018.
Additionally, earnings were lower due to the absence of a $98 million tax valuation allowance reduction, the
absence of a $79 million after-tax benefit resulting from an accrual reduction due to a transportation cost ruling
by the FERC, and $62 million less in enhanced oil recovery credits. Partly offsetting these decreases in
earnings, were higher crude oil sales volumes due to the GKA and WNS acquisitions completed in 2018.
Average production increased 32 MBOED in 2019 compared with 2018, primarily due to acquisitions at GKA
and WNS in 2018, which provided an incremental 38 MBOED of production in 2019, as well as volumes from
new wells online. These production increases were partly offset by normal field decline.
Acquisition Update
In the third quarter of 2019, we completed the Nuna discovery acreage acquisition for approximately $100
million, expanding the Kuparuk River Unit by 21,000 acres and leveraging legacy infrastructure.
46
Lower 48
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
436
1,747
(2,371)
2019
2018
2017
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per bbl)
Natural gas liquids (per bbl)
Natural gas (per mcf)
266
81
622
451
229
69
596
397
180
69
898
399
$
55.30
16.83
2.12
62.99
27.30
2.82
47.36
22.20
2.73
The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico. During
2019, the Lower 48 contributed 39 percent of our worldwide liquids production and 22 percent of our natural
gas production.
2019 vs. 2018
Lower 48 reported earnings of $436 million in 2019, compared with $1,747 million in 2018. Earnings
decreased primarily due to lower realized crude oil, NGL and natural gas prices; higher DD&A due to
increased production volumes; a $301 million after-tax impairment of our Niobrara assets; higher exploration
expenses, primarily due to a combined $197 million after-tax of leasehold impairment and dry hole costs
associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk; and
lower earnings in equity affiliates due to a combined $120 million after-tax of impairments associated with a
fair value reduction of our investment in MWCC and the disposition of our interests in the Golden Pass LNG
Terminal and Golden Pass Pipeline. Partly offsetting the decrease in earnings were increased crude oil and
NGL sales volumes in the Eagle Ford, Bakken and Permian Unconventional.
For additional information related to our impairment of MWCC, see Note 3—Variable Interest Entities in the
Notes to Consolidated Financial Statements. For more information related to the sale of our interests in
Golden Pass LNG Terminal and Golden Pass Pipeline, see Note 5—Asset Acquisitions and Dispositions in the
Notes to Consolidated Financial Statements.
Total average production increased 54 MBOED in 2019 compared with 2018. The increase was primarily due
to new production from unconventional assets in Eagle Ford, Bakken and the Permian Basin, partly offset by
normal field decline. Additionally, production decreased by 10 MBOED due to non-core dispositions in 2018.
Asset Dispositions Update
In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the Golden Pass
LNG Terminal and Golden Pass Pipeline. We have also entered into agreements to amend our contractual
obligations for retaining use of the facilities. As a result of entering into these agreements, we recognized a
before-tax impairment of $60 million in the first quarter of 2019 which is included in the “Equity in earnings
of affiliates” line on our consolidated income statement. We completed the sale in the second quarter of 2019.
See Note 15—Fair Value Measurement in the Notes to Consolidated Financial Statements, for additional
information.
In the fourth quarter of 2019, we sold our interests in the Magnolia field and platform and recognized an after-
47
tax gain of $63 million. Production from Magnolia in 2019 was less than one MBOED.
In the fourth quarter of 2019, we signed an agreement to sell our interests in the Niobrara shale play for $380
million, plus customary adjustments, and overriding royalty interests in certain future wells. We recorded an
after-tax impairment of $301 million in the fourth quarter to reduce the carrying value to fair value.
Production from Niobrara was approximately 11 MBOED in 2019. This transaction is subject to regulatory
approval and other conditions precedent and is expected to close in the first quarter of 2020.
In January 2020, we entered into an agreement to sell our interests in certain non-core properties in the Lower
48 segment for $186 million, plus customary adjustments. The assets met the held for sale criteria in January
2020 and the transaction is expected to be completed in the first quarter of 2020. No gain or loss is anticipated
on the sale. This disposition will not have a significant impact on Lower 48 production.
For additional information on these transactions, see Note 5—Asset Acquisitions and Dispositions, in the
Notes to Consolidated Financial Statements.
Canada
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
279
63
2,564
2019
2018
2017
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Bitumen (MBD)
Consolidated operations
Equity affiliates
Total bitumen
Natural gas (MMCFD)
Total Production (MBOED)
1
-
60
-
60
9
63
1
1
66
-
66
12
70
3
9
59
63
122
187
165
Average Sales Prices
Crude oil (per bbl)
Natural gas liquids (per bbl)
Bitumen (dollars per bbl)*
Consolidated operations
Equity affiliates
Total bitumen
Natural gas (per mcf)
*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.
22.29
-
22.29
1.00
31.72
-
31.72
0.49
48.73
43.70
40.87
19.87
$
43.69
21.51
21.43
23.83
22.66
1.93
Our Canadian operations consist of the Surmont oil sands development in Alberta and the liquids-rich
Montney unconventional play in British Columbia. In 2019, Canada contributed 7 percent of our worldwide
liquids production and less than one percent of our worldwide natural gas production.
2019 vs. 2018
Canada operations reported earnings of $279 million in 2019 compared with $63 million in 2018. Earnings
increased mainly due to higher realized bitumen prices, a $68 million tax benefit primarily comprised of a
previously unrecognizable tax basis related to a tax settlement, lower DD&A expense due to lower rates from
48
reserve additions, lower production and operating expenses, and a $25 million tax benefit due to a four year
phased four percent reduction in Alberta’s corporate income tax rate. Partly offsetting the increase in earnings
were lower sales volumes due to a planned turnaround at Surmont, lower production due to a mandated
production curtailment imposed by the Alberta government in January 2019, and the absence of an $80 million
tax restructuring benefit.
Total average production decreased 7 MBOED in 2019 compared with 2018. The production decrease was
primarily due to a turnaround at Surmont, which had an annualized average impact of 3 MBOED, and a
mandated production curtailment imposed by the Alberta government, which also impacted production by 3
MBOED. The curtailment program is established and administered by the Alberta Energy Regulator under the
Curtailment Rules regulation, which is currently set to expire on December 31, 2020. This program is
intended to strengthen the WCS differential to WTI at Hardisty.
Asset Disposition
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets to Cenovus Energy. Consideration for the transaction
was $11.0 billion in cash after customary adjustments, 208 million Cenovus Energy common shares and a five
year uncapped contingent payment. The contingent payment, calculated and paid on a quarterly basis, is $6
million CAD for every $1 CAD by which the WCS quarterly average crude price exceeds $52 CAD per barrel.
During 2019 and 2018, we recorded after-tax gains on dispositions for these contingent payments of $84
million and $68 million, respectively. See Note 5—Asset Acquisitions and Dispositions in the Notes to
Consolidated Financial Statements, for additional information.
Europe and North Africa
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
2,724
1,866
553
2019
2018
2017
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (dollars per bbl)
Natural gas liquids (per bbl)
Natural gas (per mcf)
138
7
478
224
149
8
503
241
142
8
484
230
$
64.94
29.37
4.92
70.71
36.87
7.65
54.21
34.07
5.70
The Europe and North Africa segment consisted of operations principally located in the Norwegian and U.K.
sectors of the North Sea, the Norwegian Sea and Libya. In 2019, our Europe and North Africa operations
contributed 16 percent of our worldwide liquids production and 17 percent of our natural gas production.
2019 vs. 2018
Earnings for Europe and North Africa operations of $2,724 million increased $858 million in 2019 compared
with 2018. The increase in earnings was primarily due to a $2.1 billion after-tax gain associated with the
completion of the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited. Earnings also
increased due to the cessation of DD&A in the second quarter of 2019 for our disposed U.K. subsidiaries when
these assets became held-for-sale. Partly offsetting the increase in earnings were the absence of a $774 million
49
after-tax gain related to the sale of a ConocoPhillips subsidiary to BP, which held 16.5 percent of our 24
percent interest in the BP-operated Clair Field in the U.K.; lower sales volumes primarily due to the U.K.
disposition to Chrysaor completed September 30, 2019; and lower realized natural gas and crude oil prices.
Average production decreased 17 MBOED in 2019, compared with 2018. The decrease was mainly due to
normal field decline and a 20 MBOED disposition impact from the sale of our U.K. assets to Chrysaor
completed September 30, 2019. Partly offsetting these production decreases were volumes from new wells
online in Norway, including the Aasta Hansteen Field which achieved first production in December of 2018.
Asset Disposition Update
On September 30, 2019, we completed the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P
Limited for proceeds of $2.2 billion after interest and customary adjustments. In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax gain associated with this transaction. Together the subsidiaries
sold indirectly held our exploration and production assets in the U.K., including $1.8 billion of ARO.
Annualized average production associated with the U.K. assets sold was 50 MBOED in 2019. Reserves
associated with the U.K. assets sold were 84 MMBOE at the time of disposition. For additional information,
see Note 5—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements.
50
Asia Pacific and Middle East
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
1,929
2,070
(1,098)
2019
2018
2017
Average Net Production
Crude oil (MBD)
Consolidated operations
Equity affiliates
Total crude oil
Natural gas liquids (MBD)
Consolidated operations
Equity affiliates
Total natural gas liquids
Natural gas (MMCFD)
Consolidated operations
Equity affiliates
Total natural gas
85
13
98
4
8
12
89
14
103
3
7
10
93
14
107
4
7
11
637
1,052
1,689
626
1,031
1,657
687
1,007
1,694
Total Production (MBOED)
392
389
401
Average Sales Prices
Crude oil (dollars per bbl)
Consolidated operations
Equity affiliates
Total crude oil
Natural gas liquids (dollars per bbl)
Consolidated operations
Equity affiliates
Total natural gas liquids
Natural gas (dollars per mcf)
Consolidated operations
Equity affiliates
Total natural gas
$
65.02
61.32
64.52
37.85
36.70
37.10
5.91
6.29
6.15
70.93
72.49
71.14
47.20
45.69
46.13
6.15
6.06
6.09
54.38
54.76
54.43
41.37
38.74
39.75
4.98
4.27
4.55
The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste
and Qatar. During 2019, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids
production and 60 percent of our natural gas production.
2019 vs. 2018
Asia Pacific and Middle East reported earnings of $1,929 million in 2019, compared with $2,070 million in
2018. The decrease in earnings was mainly due to lower realized crude oil, NGL and natural gas prices; lower
LNG and crude oil sales volumes; and lower equity in earnings of affiliates, primarily due to a deferred tax
adjustment at QG3 that resulted in a $118 million reduction to equity earnings. Partly offsetting this decrease in
earnings was a $164 million income tax benefit related to deepwater incentive tax credits from the Malaysia
Block G and a $52 million after-tax gain on disposition of our interest in the Greater Sunrise Fields.
51
Average production increased 1 percent in 2019, compared with 2018. The increase was primarily due to new
production from Malaysia, including first gas supply from KBB to PFLNG1 in the second quarter of 2019 and
first oil from Gumusut Phase 2 in the third quarter of 2019; and new wells online in China, including Bohai
Phase 3. Partly offsetting this production increase was normal field decline.
Asset Dispositions Update
In the second quarter of 2019, we recognized an after-tax gain of $52 million upon completion of the sale of our
30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million. No
production or reserve impacts were associated with the sale.
In October 2019, we entered into an agreement to sell the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary adjustments, with an effective date of January 1, 2019. In
addition, we will receive a payment of $75 million upon final investment decision of the Barossa development
project. These subsidiaries hold our 37.5 percent interest in the Barossa Project and Caldita Field, our 56.9
percent interest in the Darwin LNG Facility and Bayu-Undan Field, our 40 percent interest in the Greater
Poseidon Fields, and our 50 percent interest in the Athena Field. This transaction is expected to be completed in
the first quarter of 2020, subject to regulatory approvals and the satisfaction of other specific conditions
precedent. In 2019, production associated with the Australia-West assets to be sold was 48 MBOED. Year-end
2019 reserves associated with these assets were 17 MMBOE. We will retain our 37.5 percent interest in the
Australia Pacific LNG project and operatorship of that project’s LNG facility.
See Note 5—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements, for
additional information related to these dispositions.
Other International
Net Income Attributable to ConocoPhillips
(millions of dollars)
2019
2018
2017
$
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.
52
Corporate and Other
Net Income (Loss) Attributable to ConocoPhillips
Net interest
Corporate general and administrative expenses
Technology
Other
Millions of Dollars
2019
2018
$
$
(604)
(252)
123
771
38
(680)
(91)
109
(1,005)
(1,667)
2017
(739)
(193)
20
(1,224)
(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.
53
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Net cash provided by operating activities
Cash and cash equivalents
Short-term debt
Total debt
Total equity
Percent of total debt to capital*
Percent of floating-rate debt to total debt
*Capital includes total debt and total equity.
Millions of Dollars
Except as Indicated
2019
2018
2017
$
11,104
5,088
105
14,895
35,050
30 %
5 %
12,934
5,915
112
14,968
32,064
32
5
7,077
6,325
2,575
19,703
30,801
39
5
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.
54
The level of absolute production volumes, as well as product and location mix, impacts our cash flows. Full-
year production averaged 1,348 MBOED in 2019. Full-year production excluding Libya averaged 1,305
MBOED in 2019 and is expected to be 1,230 to 1,270 MBOED in 2020. Future production is subject to
numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment,
which may impact investment decisions; the effects of price changes on production sharing and variable-
royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies;
operating efficiencies; timing of startups and major turnarounds; political instability; weather-related
disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective
development. While we actively manage these factors, production levels can cause variability in cash flows,
although generally this variability has not been as significant as that caused by commodity prices.
To maintain or grow our production volumes on an ongoing basis, we must continue to add to our proved
reserve base. Our proved reserves generally increase as prices rise and decrease as prices decline. In 2019,
our reserve replacement, which included a net decrease of 0.1 billion BOE from sales and purchases, was 100
percent. Increased crude oil reserves accounted for approximately 55 percent of the total change in reserves.
Our organic reserve replacement, which excludes the impact of sales and purchases, was 117 percent in 2019.
Approximately 51 percent of organic reserve additions are from Lower 48, 13 percent from Alaska, 12 percent
from Canada, 12 percent from Europe and North Africa and 12 percent from Asia Pacific and Middle East.
In the five years ended December 31, 2019, our reserve replacement, which included a decrease of 2.0 billion
BOE from sales and purchases, was negative 34 percent, reflecting the impact of asset dispositions and lower
prices during that period. Our organic reserve replacement during the five years ended December 31, 2019,
was 40 percent, reflecting development activities as well as lower prices during that period.
Historically our reserve replacement has varied considerably year to year contingent upon the timing of major
projects which may have long lead times between capital investment and production. In the last several years,
more of our capital has been allocated to short cycle time, onshore, unconventional plays. Accordingly, we
believe our recent success in replacing reserves can be viewed on a trailing three-year basis.
In the three years ended December 31, 2019, our reserve replacement was 23 percent, reflecting the impact of
asset dispositions during that period. Our organic reserve replacement during the three years ended December
31, 2019, which excludes a decrease of 1.8 billion BOE related to sales and purchases, was 143 percent,
reflecting reserve additions from development activities.
Reserve replacement represents the net change in proved reserves, net of production, divided by our current
year production, as shown in our supplemental reserve table disclosures. For additional information about our
2020 capital budget, see the “2020 Capital Budget” section within “Capital Resources and Liquidity” and for
additional information on proved reserves, including both developed and undeveloped reserves, see the “Oil
and Gas Operations” section of this report.
As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are
imprecise; therefore, each year reserves may be revised upward or downward due to the impact of changes in
commodity prices or as more technical data becomes available on reservoirs. We have reported revisions as
increases to reserves in the current period, however in prior periods, reported revisions as decreases to
reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.
Investing Activities
Proceeds from asset sales in 2019 were $3.0 billion. We completed the sale of two ConocoPhillips U.K.
subsidiaries to Chrysaor E&P Limited for $2.2 billion. We also completed the sale of several assets including
our 30 percent interest in the Greater Sunrise Fields for $350 million and received $106 million of contingent
payments from Cenovus Energy.
In the fourth quarter of 2019, we entered into an agreement to sell the subsidiaries that hold our Australia-West
assets and operations to Santos for $1.39 billion, plus customary adjustments. In addition, we will receive a
payment of $75 million upon final investment decision of the Barossa development project. Also in the fourth
55
quarter of 2019, we signed an agreement to sell our interests in the Niobrara shale play for $380 million, plus
customary adjustments, and overriding royalty interests in certain future wells. Both transactions are subject to
regulatory approval and other conditions precedent and expected to close in the first quarter of 2020.
Investing activities in 2019 also included net purchases of $2.9 billion of investments in short-term and long-
term financial instruments. These investments include time deposits, commercial paper as well as debt
securities classified as available for sale. The investment in short-term instruments was $2.8 billion, the
remaining $0.1 billion was invested in long-term debt securities. For additional information, see Note 14–
Derivative and Financial Instruments.
Proceeds from asset sales in 2018 were $1.1 billion. We completed several undeveloped acreage transactions
in our Lower 48 segment for a total of $267 million after customary adjustments and another transaction in our
Lower 48 segment for $112 million after customary adjustments. We completed the sale of our interests in the
Barnett to Lime Rock Resources for $196 million after customary adjustments. We also completed the sale of
a ConocoPhillips subsidiary to BP and received $253 million net proceeds. The subsidiary held 16.5 percent
of our 24 percent interest in the BP-operated Clair Field in the U.K. During 2018, we received $95 million of
contingent payments from Cenovus Energy.
For additional information on our dispositions, see Note 5—Asset Acquisitions and Dispositions in the Notes
to Consolidated Financial Statements.
Commercial Paper and Credit Facilities
We have a revolving credit facility totaling $6.0 billion, expiring in May 2023. Our revolving credit facility
may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as
support for our commercial paper program. The revolving credit facility is broadly syndicated among financial
institutions and does not contain any material adverse change provisions or any covenants requiring
maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default
provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more
by ConocoPhillips, or any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight federal funds rate or prime rates offered by
certain designated banks in the U.S. The agreement calls for commitment fees on available, but unused,
amounts. The agreement also contains early termination rights if our current directors or their approved
successors cease to be a majority of the Board of Directors.
The revolving credit facility supports the ConocoPhillips Company $6.0 billion commercial paper program,
which is primarily a funding source for short-term working capital needs. Commercial paper maturities are
generally limited to 90 days. We had no commercial paper outstanding in programs in place at December 31,
2019 or December 31, 2018. We had no direct outstanding borrowings or letters of credit under the revolving
credit facility at December 31, 2019 and December 31, 2018. Since we had no commercial paper outstanding
and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving
credit facility at December 31, 2019.
Our current long-term debt ratings remained unchanged in 2019 and are as follows: Fitch - “A” with a “stable”
outlook; Moody’s Investors Services - “A3” with a “stable” outlook; and Standard & Poor’s - “A” with a
stable outlook. We do not have any ratings triggers on any of our corporate debt that would cause an
automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating.
If our credit rating were downgraded, it could increase the cost of corporate debt available to us and restrict our
access to the commercial paper markets. If our credit rating were to deteriorate to a level prohibiting us from
accessing the commercial paper market, we would still be able to access funds under our revolving credit
facility.
Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions
requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters
56
of credit as collateral. At December 31, 2019 and 2018, we had direct bank letters of credit of $277 million
and $323 million, respectively, which secured performance obligations related to various purchase
commitments incident to the ordinary conduct of business. In the event of credit ratings downgrades, we may
be required to post additional letters of credit.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we, as a well-known
seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity
securities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we enter into
numerous agreements with other parties to pursue business opportunities, which share costs and apportion
risks among the parties as governed by the agreements.
For information about guarantees, see Note 12—Guarantees, in the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures” section.
Our debt balance at December 31, 2019, was $14,895 million, a decrease of $73 million from the balance at
December 31, 2018. For more information on Debt, see Note 11—Debt, in the Notes to Consolidated
Financial Statements.
On January 30, 2019, we announced a quarterly dividend of $0.305 per share. The dividend was paid on
March 1, 2019, to stockholders of record at the close of business on February 11, 2019. On May 1, 2019, we
announced a quarterly dividend of $0.305 per share. The dividend was paid on June 3, 2019, to stockholders
of record at the close of business on May 13, 2019. On July 11, 2019, we announced a quarterly dividend of
$0.305 per share. The dividend was paid on September 3, 2019, to stockholders of record at the close of
business on July 22, 2019. On October 7, 2019, we announced a 38 percent increase in the quarterly dividend
to $0.42 per share. The dividend was paid on December 2, 2019, to stockholders of record at the close of
business on October 17, 2019. In February 2020, we announced a quarterly dividend of $0.42 per share,
payable March 2, 2020, to stockholders of record at the close of business on February 14, 2020.
In late 2016, we initiated our current share repurchase program. As of December 31, 2019, we had announced
a total authorization to repurchase $15 billion of our common stock. We repurchased $3 billion in 2017, $3
billion in 2018 and $3.5 billion in 2019. Of the remaining authorization, we expect to repurchase $3 billion in
2020. In February 2020, we announced that the Board of Directors approved an increase to our authorization
from $15 billion to $25 billion, to support our plan for future share repurchases. Whether we undertake these
additional repurchases is ultimately subject to numerous considerations, market conditions and other factors.
See Risk Factors -“Our ability to declare and pay dividends and repurchase shares is subject to certain
considerations.” Since our share repurchase program began in November 2016, we have repurchased 169
million shares at a cost of $9.6 billion through December 31, 2019.
57
Contractual Obligations
The table below summarizes our aggregate contractual fixed and variable obligations as of December 31, 2019:
Debt obligations (a)
Finance lease obligations (b)
Total debt
Interest on debt
Operating lease obligations (c)
Purchase obligations (d)
Other long-term liabilities
Pension and postretirement benefit
contributions (e)
Asset retirement obligations (f)
Accrued environmental costs (g)
Unrecognized tax benefits (h)
Total
Millions of Dollars
Payments Due by Period
Total
Up to 1
Year
Years
2–3
Years
4–5
After
5 Years
$
14,175
720
14,895
11,339
1,050
8,671
1,375
6,206
171
82
43,789
$
18
87
105
856
379
3,237
440
997
28
82
6,124
1,018
157
1,175
1,671
377
1,745
540
282
33
(h)
5,823
605
141
746
1,603
145
1,327
12,534
335
12,869
7,209
149
2,362
395
309
21
(h)
4,546
-
4,618
89
(h)
27,296
(a)
(b)
(c)
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.
See Note 17—Non-Mineral Leases, in the Notes to Consolidated Financial Statements, for additional
information.
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.
58
(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
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Capital Program
Millions of Dollars
2019
2018
2017
$
$
1,513
3,394
368
708
584
8
61
6,636
1,298
3,184
477
877
718
6
190
6,750
815
2,136
202
872
482
21
63
4,591
Our capital expenditures and investments for the three-year period ended December 31, 2019, totaled $18.0
billion. The 2019 expenditures supported key exploration and developments, primarily:
• Development, appraisal and exploration activities in the Lower 48, including Eagle Ford, Permian
Unconventional, and Bakken.
• Appraisal and development activities in Alaska related to the Western North Slope; development
activities in the Greater Kuparuk Area and the Greater Prudhoe Area; leasehold acquisition in the
Greater Kuparuk Area.
• Development activities across assets in Norway, as well as for assets in the U.K. that recently have
been sold.
• Optimization of oil sands development and appraisal activities in liquids-rich plays in Canada.
• Signature bonus for Indonesia Corridor Block production sharing contract, as well as continued
development in China, Malaysia, Australia, and Indonesia.
2020 CAPITAL BUDGET
In February 2020, we announced 2020 operating plan capital of $6.5 billion to $6.7 billion. The plan includes
funding for ongoing development drilling programs, major projects, exploration and appraisal activities, as
well as base maintenance. Capital spend is expected to be higher in the first quarter largely from winter
construction and exploration and appraisal drilling in Alaska. This guidance does not include capital for
acquisitions.
For information on PUDs and the associated costs to develop these reserves, see the “Oil and Gas Operations”
section in this report.
Contingencies
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed
against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the
placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active
59
and inactive sites. We regularly assess the need for accounting recognition or disclosure of these
contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a
liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be
reasonably estimated and no amount within the range is a better estimate than any other amount, then the
minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party
recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With
respect to income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases
where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent
liability exposures will exceed current accruals by an amount that would have a material adverse impact on our
consolidated financial statements. For information on other contingencies, see “Critical Accounting
Estimates” and Note 13—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Legal and Tax Matters
We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty
and severance tax payments, gas measurement and valuation methods, contract disputes, environmental
damages, climate change, personal injury, and property damage. Our primary exposures for such matters
relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties and
claims of alleged environmental contamination from historic operations. We will continue to defend ourselves
vigorously in these matters.
Our legal organization applies its knowledge, experience and professional judgment to the specific
characteristics of our cases, employing a litigation management process to manage and monitor the legal
proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in
individual cases. This process also enables us to track those cases that have been scheduled for trial and/or
mediation. Based on professional judgment and experience in using these litigation management tools and
available information about current developments in all our cases, our legal organization regularly assesses the
adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new
accruals, is required. See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for
additional information about income tax-related contingencies.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations
as other companies in our industry. The most significant of these environmental laws and regulations include,
among others, the:
• U.S. Federal Clean Air Act, which governs air emissions.
• U.S. Federal Clean Water Act, which governs discharges to water bodies.
• European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals
(REACH).
• U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or
Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances
at sites where hazardous substance releases have occurred or are threatening to occur.
• U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage
and disposal of solid waste.
• U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore
facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and
owners and operators of vessels are liable for removal costs and damages that result from a discharge
of oil into navigable waters of the U.S.
• U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires
facilities to report toxic chemical inventories with local emergency planning committees and response
departments.
60
• U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground
injection wells.
• U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S.
waters and impose liability for the cost of pollution cleanup resulting from operations, as well as
potential liability for pollution damages.
• European Union Trading Directive resulting in European Emissions Trading Scheme.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water,
establish water quality limits and establish standards and impose obligations for the remediation of releases of
hazardous substances and hazardous wastes. They also, in most cases, require permits in association with new
or modified operations. These permits can require an applicant to collect substantial information in connection
with the application process, which can be expensive and time consuming. In addition, there can be delays
associated with notice and comment periods and the agency’s processing of the application. Many of the
delays associated with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws
and regulations governing these same types of activities. While similar, in some cases these regulations may
impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or
transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor
easily determinable as new standards, such as air emission standards and water quality standards, continue to
evolve. However, environmental laws and regulations, including those that may arise to address concerns
about global climate change, are expected to continue to have an increasing impact on our operations in the
U.S. and in other countries in which we operate. Notable areas of potential impacts include air emission
compliance and remediation obligations in the U.S. and Canada.
An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of
oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal or
national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing
currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many
decades, a number of new laws, regulations and permitting requirements are under consideration by various
state environmental agencies, and others which could result in increased costs, operating restrictions,
operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions
on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas
investments. We have adopted operating principles that incorporate established industry standards designed to
meet or exceed government requirements. Our practices continually evolve as technology improves and
regulations change.
We also are subject to certain laws and regulations relating to environmental remediation obligations
associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their
state equivalents. Longer-term expenditures are subject to considerable uncertainty and may fluctuate
significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state
environmental agencies alleging we are a potentially responsible party under CERCLA or an equivalent state
statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by
private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various
sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of
December 31, 2019, there were 15 sites around the U.S. in which we were identified as a potentially
responsible party under CERCLA and comparable state laws.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs
because the percentage of waste attributable to us, versus that attributable to all other potentially responsible
61
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.
62
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 21st Conference of the Parties to the United
Nations Framework on Climate Change, setting out a new process for achieving global emission
reductions. While the U.S. announced its intention to withdraw from the Paris Agreement, there is no
guarantee that the commitments made by the U.S. will not be implemented, in whole or in part, by
U.S. state and local governments or by major corporations headquartered in the U.S.
In the U.S., some additional form of regulation may be forthcoming in the future at the federal and state levels
with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation
of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance
with laws and regulations, or required acquisition or trading of emission allowances. We are working to
continuously improve operational and energy efficiency through resource and energy conservation throughout
our operations.
Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG
reduction policies could significantly increase our costs, reduce demand for fossil energy derived products,
impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations
could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate
impact on our financial performance, either positive or negative, will depend on a number of factors, including
but not limited to:
• Whether and to what extent legislation or regulation is enacted.
• The timing of the introduction of such legislation or regulation.
63
• 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.
64
Several Louisiana parishes and individual landowners have filed lawsuits against oil and gas companies,
including ConocoPhillips, seeking compensatory damages in connection with historical oil and gas operations
in Louisiana. All parish lawsuits are stayed pending an appeal to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or state court. ConocoPhillips will vigorously defend against
these lawsuits.
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards.
Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more
likely than not, be realized. Based on our historical taxable income, our expectations for the future, and
available tax-planning strategies, management expects the net deferred tax assets will be realized as offsets to
reversing deferred tax liabilities.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with GAAP requires management to select appropriate
accounting policies and to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. See Note 1—Accounting Policies, in the Notes to Consolidated Financial
Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve
judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts
would have been reported under different conditions, or if different assumptions had been used. These critical
accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least
annually. We believe the following discussions of critical accounting estimates, along with the discussion of
deferred tax asset valuation allowances in this report, address all important accounting areas where the nature
of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to
account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas
industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved
reserves, is expensed as incurred, similar to accounting for research and development costs. However,
leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending
determination of whether proved oil and gas reserves have been recognized.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration
and drilling efforts to date. For relatively small individual leasehold acquisition costs, management exercises
judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and
gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas
with limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally
judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that
product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment
charge that is reported in exploration expense. This judgmental probability percentage is reassessed and
adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory
activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted
prospectively.
At year-end 2019, the remaining $3.5 billion of net capitalized unproved property costs consisted primarily of
individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells
currently being drilled, suspended exploratory wells, and capitalized interest. Of this amount, approximately
$2.1 billion is concentrated in 10 major development areas, the majority of which are not expected to move to
proved properties in 2020, and $0.6 billion is held for sale. Management periodically assesses individually
65
significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for
commercialization.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending
a determination of whether potentially economic oil and gas reserves have been discovered by the drilling
effort to justify development.
If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized
on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating
viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but
the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future
market conditions will improve or new technologies will be found that would make the development
economically profitable. Often, the ability to move into the development phase and record proved reserves is
dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately
beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such
approvals and permits, and believe they will be obtained. Once all required approvals and permits have been
obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as
proved reserves. For complex exploratory discoveries, it is not unusual to have exploratory wells remain
suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic
work on the potential oil and gas field or while we seek government or co-venturer approval of development
plans or seek environmental permitting. Once a determination is made the well did not encounter potentially
economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.
Management reviews suspended well balances quarterly, continuously monitors the results of the additional
appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines
the potential field does not warrant further investment in the near term. Criteria utilized in making this
determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected
development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or
contract negotiations, and our expected return on investment.
At year-end 2019, total suspended well costs were $1,020 million, compared with $856 million at year-end
2018. For additional information on suspended wells, including an aging analysis, see Note 8—Suspended
Wells and Other Exploration Expenses, in the Notes to Consolidated Financial Statements.
Proved Reserves
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only
approximate amounts because of the judgments involved in developing such information. Reserve estimates
are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan,
historical extraction recovery and processing yield factors, installed plant operating capacity and approved
operating limits. The reliability of these estimates at any point in time depends on both the quality and
quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of
“proved” reserve estimates due to the importance of these estimates to better understand the perceived value
and future cash flows of a company’s operations. There are several authoritative guidelines regarding the
engineering criteria that must be met before estimated reserves can be designated as “proved.” Our
geosciences and reservoir engineering organization has policies and procedures in place consistent with these
authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our
proved reserves held by consolidated companies, as well as our share of equity affiliates.
Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes
occur, and take into account recent production and subsurface information about each field. Also, as required
by current authoritative guidelines, the estimated future date when an asset will be permanently shut down for
economic reasons is based on 12-month average prices and current costs. This estimated date when production
66
will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to
year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline
and increase as prices rise.
Our proved reserves include estimated quantities related to PSCs, reported under the “economic interest”
method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices; recoverable
operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs
will change inversely to changes in commodity prices. We would expect reserves from these contracts to
decrease when product prices rise and increase when prices decline.
The estimation of proved developed reserves also is important to the income statement because the proved
developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of the
DD&A of the capitalized costs for that asset. At year-end 2019, the net book value of productive PP&E
subject to a unit-of-production calculation was approximately $35 billion and the DD&A recorded on these
assets in 2019 was approximately $5.8 billion. The estimated proved developed reserves for our consolidated
operations were 3.3 billion BOE at the end of 2018 and 3.2 billion BOE at the end of 2019. If the estimates of
proved reserves used in the unit-of-production calculations had been lower by 10 percent across all
calculations, before-tax DD&A in 2019 would have increased by an estimated $642 million.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances
indicate a possible significant deterioration in future cash flows expected to be generated by an asset group and
annually in the fourth quarter following updates to corporate planning assumptions. If there is an indication
the carrying amount of an asset may not be recovered, the asset is monitored by management through an
established process where changes to significant assumptions such as prices, volumes and future development
plans are reviewed. If, upon review, the sum of the undiscounted before-tax cash flows is less than the
carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets
are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are
identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a
field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived
assets, the fair value of impaired assets is typically determined based on the present values of expected future
cash flows using discount rates believed to be consistent with those used by principal market participants, or
based on a multiple of operating cash flow validated with historical market transactions of similar assets where
possible. The expected future cash flows used for impairment reviews and related fair value calculations are
based on judgmental assessments of future production volumes, commodity prices, operating costs and capital
decisions, considering all available information at the date of review. Differing assumptions could affect the
timing and the amount of an impairment in any period. See Note 9—Impairments, in the Notes to
Consolidated Financial Statements, for additional information.
Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment
when there is evidence of a loss in value and annually following updates to corporate planning assumptions.
Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of
sustained earnings capacity which would justify the current investment amount, or a current fair value less than
the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an
impairment charge is recognized for the difference between the investment’s carrying value and its estimated
fair value. When determining whether a decline in value is other than temporary, management considers
factors such as the length of time and extent of the decline, the investee’s financial condition and near-term
prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for
any anticipated recovery in the market value of the investment. Since quoted market prices are usually not
available, the fair value is typically based on the present value of expected future cash flows using discount
rates believed to be consistent with those used by principal market participants, plus market analysis of
comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the
amount of an impairment of an investment in any period. See the “APLNG” section of Note 6—Investments,
Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional
67
information.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove tangible
equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset
removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas
platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. The fair values
of obligations for dismantling and removing these facilities are recorded as a liability and an increase to PP&E
at the time of installation of the asset based on estimated discounted costs. Estimating future asset removal
costs is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts
and regulations often have vague descriptions of what removal practices and criteria must be met when the
removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance
considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and
inflation rates, are also subject to change.
Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases
to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as
well as previously sold assets for which we retained the asset removal obligation, an increase in the asset
removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the
increased obligation would immediately be subject to impairment, due to the low fair value of these properties.
In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have
certain environmental-related projects. These are primarily related to remediation activities required by
Canada and various states within the U.S. at exploration and production sites. Future environmental
remediation costs are difficult to estimate because they are subject to change due to such factors as the
uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be
required, and the determination of our liability in proportion to that of other responsible parties. See Note
10—Asset Retirement Obligations and Accrued Environmental Costs, in the Notes to Consolidated Financial
Statements, for additional information.
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are
important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit
expense in the income statement. The actuarial determination of projected benefit obligations and company
contribution requirements involves judgment about uncertain future events, including estimated retirement
dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future
health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized
nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected
benefit obligations and company contribution requirements. For Employee Retirement Income Security Act-
governed pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination
of the judgmental assumptions used in determining required company contributions into the plans. Due to
differing objectives and requirements between financial accounting rules and the pension plan funding
regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two
purposes differ in certain important respects. Ultimately, we will be required to fund all vested benefits under
pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental
assumptions used in the actuarial calculations significantly affect periodic financial statements and funding
patterns over time. Projected benefit obligations are particularly sensitive to the discount rate assumption. A
100 basis-point decrease in the discount rate assumption would increase projected benefit obligations by
$1,000 million. Benefit expense is sensitive to the discount rate and return on plan assets assumptions. A
100 basis-point decrease in the discount rate assumption would increase annual benefit expense by
$100 million, while a 100 basis-point decrease in the return on plan assets assumption would increase annual
benefit expense by $60 million. In determining the discount rate, we use yields on high-quality fixed income
investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility
68
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.
69
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.
70
• Changes in international trade relationships, including the imposition of trade restrictions or tariffs
relating to crude oil, bitumen, natural gas, LNG, NGLs and any materials or products (such as
aluminum and steel) used in the operation of our business.
• Substantial investment in and development use of, competing or alternative energy sources, including
as a result of existing or future environmental rules and regulations.
• Liability for remedial actions, including removal and reclamation obligations, under existing or future
environmental regulations and litigation.
• Significant operational or investment changes imposed by existing or future environmental statutes
and regulations, including international agreements and national or regional legislation and regulatory
measures to limit or reduce GHG emissions.
• Liability resulting from litigation or our failure to comply with applicable laws and regulations.
• General domestic and international economic and political developments, including armed hostilities;
expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas,
LNG and NGLs pricing, regulation or taxation; the impact of and uncertainty surrounding the U.K.’s
decision to withdraw from the EU; and other political, economic or diplomatic developments.
• Volatility in the commodity futures markets.
• Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules
applicable to our business, including changes resulting from the implementation and interpretation of
the Tax Cuts and Jobs Act.
• Competition and consolidation in the oil and gas E&P industry.
• Any limitations on our access to capital or increase in our cost of capital, including as a result of
illiquidity or uncertainty in domestic or international financial markets.
• Our inability to execute, or delays in the completion, of any asset dispositions or acquisitions we elect
to pursue.
• Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for asset
dispositions or acquisitions, or that such approvals may require modification to the terms of the
transactions or the operation of our remaining business.
• Potential disruption of our operations as a result of asset dispositions or acquisitions, including the
diversion of management time and attention.
• Our inability to deploy the net proceeds from any asset dispositions we undertake in the manner and
timeframe we currently anticipate, if at all.
• Our inability to liquidate the common stock issued to us by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem acceptable, or at all.
• The operation and financing of our joint ventures.
• The ability of our customers and other contractual counterparties to satisfy their obligations to us,
including our ability to collect payments when due from the government of Venezuela or PDVSA.
• Our inability to realize anticipated cost savings and expenditure reductions.
• The factors generally described in Item 1A—Risk Factors in this 2019 Annual Report on Form 10-K
and any additional risks described in our other filings with the SEC.
71
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our
cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We
may use financial and commodity-based derivative contracts to manage the risks produced by changes in the
prices of natural gas, crude oil and related products; fluctuations in interest rates and foreign currency
exchange rates; or to capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board
of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient
liquidity. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the
company, and compliance with these limits is monitored daily. The Executive Vice President and Chief
Financial Officer, who reports to the Chief Executive Officer, monitors commodity price risk and risks
resulting from foreign currency exchange rates and interest rates. The Commercial organization manages our
commercial marketing, optimizes our commodity flows and positions, and monitors risks.
Commodity Price Risk
Our Commercial organization uses futures, forwards, swaps and options in various markets to accomplish the
following objectives:
• Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we
use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas
consumers, to floating market prices.
• Enable us to use market knowledge to capture opportunities such as moving physical commodities to
more profitable locations and storing commodities to capture seasonal or time premiums. We may use
derivatives to optimize these activities.
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the
effect of adverse changes in market conditions on the derivative financial instruments and derivative
commodity instruments we hold or issue, including commodity purchases and sales contracts recorded on the
balance sheet at December 31, 2019, as derivative instruments. Using Monte Carlo simulation, a 95 percent
confidence level and a one-day holding period, the VaR for those instruments issued or held for trading
purposes or held for purposes other than trading at December 31, 2019 and 2018, was immaterial to our
consolidated cash flows and net income attributable to ConocoPhillips.
Interest Rate Risk
The following table provides information about our debt instruments that are sensitive to changes in U.S.
interest rates. The table presents principal cash flows and related weighted-average interest rates by expected
maturity dates. Weighted-average variable rates are based on effective rates at the reporting date. The
carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate debt is
measured using prices available from a pricing service that is corroborated by market data.
72
Expected Maturity Date
Year-End 2019
2020
2021
2022
2023
2024
Remaining years
Total
Fair value
Year-End 2018
2019
2020
2021
2022
2023
Remaining years
Total
Fair value
Millions of Dollars Except as Indicated
Debt
Fixed Average
Interest
Rate
Rate
Maturity
Floating Average
Interest
Rate
Maturity
Rate
$
$
$
$
$
$
-
140
343
106
456
12,143
13,188
17,325
17
-
123
343
106
12,599
13,188
15,364
- % $
6.24
2.54
7.20
3.52
6.25
$
$
- % $
-
9.13
2.54
7.20
6.16
$
$
-
-
500
-
-
283
783
783
-
-
-
500
-
283
783
783
- %
-
2.81
-
-
1.65
- %
-
-
3.52
-
1.78
Foreign Currency Exchange Risk
We have foreign currency exchange rate risk resulting from international operations. We do not
comprehensively hedge the exposure to currency exchange rate changes although we may choose to selectively
hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local
currency tax payments, dividends and cash returns from net investments in foreign affiliates to be remitted
within the coming year, and investments in equity securities.
At December 31, 2019 and 2018, we held foreign currency exchange forwards hedging cross-border
commercial activity and foreign currency exchange swaps and options for purposes of mitigating our cash-
related exposures. Although these forwards, swaps and options hedge exposures to fluctuations in exchange
rates, we elected not to utilize hedge accounting. As a result, the change in the fair value of these foreign
currency exchange derivatives is recorded directly in earnings.
At December 31, 2019, we had outstanding foreign currency exchange forward contracts to sell $1.35 billion
CAD at $0.748 CAD against the U.S. dollar. At December 31, 2018, we had outstanding foreign currency
zero-cost collars buying the right to sell $1.25 billion CAD at $0.707 CAD and selling the right to buy $1.25
billion CAD at $0.842 CAD against the U.S. dollar. Based on the assumed volatility in the fair value
calculation, the net fair value of these foreign currency contracts at December 31, 2019 and December 31,
2018, was a before-tax loss of $28 million and a before-tax gain of $6 million, respectively. Based on an
adverse hypothetical 10 percent change in the December 2019 and December 2018 exchange rate, this would
result in an additional before-tax loss of $115 million and $17 million, respectively. The sensitivity analysis is
based on changing one assumption while holding all other assumptions constant, which in practice may be
unlikely to occur, as changes in some of the assumptions may be correlated.
73
The gross notional and fair value of these positions at December 31, 2019 and 2018, were as follows:
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy British pound
Sell Canadian dollar, buy U.S. dollar
Buy Canadian dollar, sell U.S. dollar
Sell British pound, buy Norwegian krone
Sell British pound, buy euro
Buy British pound, sell euro
*Denominated in USD, CAD and GBP.
**Denominated in USD.
Notional*
2019
USD
CAD
CAD
GBP
GBP
GBP
-
1,350
13
-
-
4
In Millions
2018
805
1,250
8
9
12
-
Fair Value**
2019
2018
-
(28)
-
-
-
-
(5)
6
-
-
-
-
For additional information about our use of derivative instruments, see Note 14—Derivative and Financial
Instruments, in the Notes to Consolidated Financial Statements.
74
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
Report of Management ...........................................................................................................................
Page
76
INDEX TO FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm .................................................................
77
Consolidated Income Statement for the years ended December 31, 2019, 2018 and 2017 ....................
81
Consolidated Statement of Comprehensive Income for the years ended
December 31, 2019, 2018 and 2017 ..................................................................................................
82
Consolidated Balance Sheet at December 31, 2019 and 2018 ................................................................
83
Consolidated Statement of Cash Flows for the years ended December 31, 2019, 2018 and 2017 .........
84
Consolidated Statement of Changes in Equity for the years ended
December 31, 2019, 2018 and 2017 ..................................................................................................
85
Notes to Consolidated Financial Statements ...........................................................................................
86
Supplementary Information
Oil and Gas Operations .............................................................................................................
150
Selected Quarterly Financial Data .............................................................................................
178
Condensed Consolidating Financial Information ......................................................................
179
75
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
Ryan M. Lance
Chairman and
Chief Executive Officer
February 18, 2020
/s/ Don E. Wallette, Jr.
Don E. Wallette, Jr.
Executive Vice President and
Chief Financial Officer
76
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.
77
Description of
the Matter
Accounting for asset retirement obligations for certain offshore properties
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.
Description of
the Matter
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
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.
78
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
79
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
80
Consolidated Income Statement
ConocoPhillips
Years Ended December 31
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
Other expenses
Total Costs and Expenses
Income (loss) before income taxes
Income tax provision (benefit)
Net income (loss)
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock (dollars)
Basic
Diluted
Average Common Shares Outstanding (in thousands)
Basic
Diluted
See Notes to Consolidated Financial Statements.
$
$
$
Millions of Dollars
2019
2018
2017
32,567
779
1,966
1,358
36,670
11,842
5,322
556
743
6,090
405
953
326
778
66
65
27,146
9,524
2,267
7,257
(68)
7,189
36,417
1,074
1,063
173
38,727
14,294
5,213
401
369
5,956
27
1,048
353
735
(17)
375
28,754
9,973
3,668
6,305
(48)
6,257
29,106
772
2,177
529
32,584
12,475
5,162
427
934
6,845
6,601
809
362
1,098
35
451
35,199
(2,615)
(1,822)
(793)
(62)
(855)
6.43
6.40
5.36
5.32
(0.70)
(0.70)
1,117,260
1,123,536
1,166,499
1,175,538
1,221,038
1,221,038
81
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years Ended December 31
Millions of Dollars
2019
$
-
7,257
(35)
(35)
(55)
Net Income (Loss)
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period
Reclassification adjustment for amortization of prior
service credit included in net income (loss)
Net change
Net actuarial gain (loss) arising during the period
Reclassification adjustment for amortization of net
actuarial losses included in net income (loss)
Net change
Nonsponsored plans*
Income taxes on defined benefit plans
Defined benefit plans, net of tax
Unrealized holding loss on securities
Unrealized loss on securities, net of tax
Foreign currency translation adjustments
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax
Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Income (Loss) Attributable to ConocoPhillips
*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.
See Notes to Consolidated Financial Statements.
146
91
(3)
(2)
51
-
-
699
(4)
695
746
8,003
(68)
7,935
$
2018
6,305
(7)
(40)
(47)
(150)
279
129
(1)
(42)
39
-
-
(645)
3
(642)
(603)
5,702
(48)
5,654
2017
(793)
2
(38)
(36)
19
247
266
(2)
(81)
147
(58)
(58)
586
-
586
675
(118)
(62)
(180)
82
Consolidated Balance Sheet
At December 31
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable (net of allowance of $13 million in 2019
and $25 million in 2018)
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 $55,477 million in 2019 and $64,899 million in 2018)
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 (2,500,000,000 shares authorized at $0.01 par value)
Issued (2019—1,795,652,203 shares; 2018—1,791,637,434 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2019—710,783,814 shares; 2018—653,288,213 shares)
Accumulated other comprehensive loss
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
See Notes to Consolidated Financial Statements.
ConocoPhillips
Millions of Dollars
2019
2018
5,088
3,028
3,267
134
2,111
1,026
2,259
16,913
8,687
219
42,269
2,426
70,514
3,176
24
105
1,030
663
2,045
7,043
14,790
5,352
4,634
1,781
1,864
35,464
5,915
248
3,920
147
1,462
1,007
575
13,274
9,329
335
45,698
1,344
69,980
3,863
32
112
1,320
809
1,259
7,395
14,856
7,688
5,021
1,764
1,192
37,916
18
46,983
(46,405)
(5,357)
39,742
34,981
69
35,050
70,514
18
46,879
(42,905)
(6,063)
34,010
31,939
125
32,064
69,980
$
$
$
$
83
Consolidated Statement of Cash Flows
ConocoPhillips
Years Ended December 31
Cash Flows From Operating Activities
Net income (loss)
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
Undistributed equity earnings
Gain on dispositions
Other
Working capital adjustments
Decrease (increase) in accounts and notes receivable
Decrease (increase) in inventories
Decrease (increase) in prepaid expenses and other current assets
Increase (decrease) in accounts payable
Increase (decrease) in taxes and other accruals
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net sales (purchases) of investments
Collection of advances/loans—related parties
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Used in Financing Activities
Millions of Dollars
2019
2018
$
7,257
6,305
6,090
405
421
326
(444)
594
(1,966)
(1,000)
505
(67)
37
(378)
(676)
11,104
(6,636)
(103)
3,012
(2,910)
127
(108)
(6,618)
(80)
(30)
(3,500)
(1,500)
(119)
(5,229)
5,956
27
95
353
283
152
(1,063)
191
235
86
(55)
(52)
421
12,934
(6,750)
(68)
1,082
1,620
119
154
(3,843)
(4,995)
121
(2,999)
(1,363)
(123)
(9,359)
2017
(793)
6,845
6,601
566
362
(3,681)
(232)
(2,177)
(429)
(886)
(55)
69
265
622
7,077
(4,591)
132
13,860
(1,790)
115
36
7,762
(7,876)
(63)
(3,000)
(1,305)
(112)
(12,356)
Effect of Exchange Rate Changes on Cash, Cash Equivalents
and Restricted Cash
(46)
(117)
232
Net Change in Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, Cash Equivalents and Restricted Cash at End of Period
Restricted cash of $90 million and $184 million are included in the “Prepaid expenses and other current assets” and “Other assets” lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2019.
Restricted cash totaling $236 million is included in the “Other assets” line of our Consolidated Balance Sheet as of December 31, 2018.
See Notes to Consolidated Financial Statements.
(385)
6,536
6,151
(789)
6,151
5,362
$
2,715
3,610
6,325
84
Consolidated Statement of Changes in Equity
ConocoPhillips
Attributable to ConocoPhillips
Millions of Dollars
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-
Controlling
Interests
252
62
$
$
18
18
115
675
(6,193)
(3,000)
(5,518)
(1,305)
46,507
46,622
(36,906)
(39,906)
31,548
(855)
December 31, 2016
Net income (loss)
Other comprehensive income
Dividends paid ($1.06 per share of common stock)
Repurchase of company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Other
December 31, 2017
Net income
Other comprehensive loss
Dividends paid ($1.16 per share of common stock)
Repurchase of company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Changes in Accounting Principles*
Other
December 31, 2018
Net income
Other comprehensive income
Dividends paid ($1.34 per share of common stock)
Repurchase of company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Changes in Accounting Principles**
Other
December 31, 2019
18
*Cumulative effect of the adoption of ASC Topic 606, "Revenue from Contracts with Customers," and ASU No. 2016-01, "Recognition and
Measurement of Financial Assets and Liabilities," at January 1, 2018.
**See Note 2—Changes in Accounting Principles for additional information.
See Notes to Consolidated Financial Statements.
(278)
3
34,010
7,189
3
29,391
6,257
40
3
39,742
(46,405)
(42,905)
46,983
46,879
(1,500)
(1,363)
(3,500)
(6,063)
(2,999)
(5,357)
(603)
746
104
257
(40)
18
58
$
$
(120)
194
48
(121)
4
125
68
(128)
4
69
Total
35,226
(793)
675
(1,305)
(3,000)
(120)
115
3
30,801
6,305
(603)
(1,363)
(2,999)
(121)
257
(220)
7
32,064
7,257
746
(1,500)
(3,500)
(128)
104
-
7
35,050
85
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1—Accounting Policies
■
■
■
■
■
■
Consolidation Principles and Investments—Our consolidated financial statements include the accounts
of majority-owned, controlled subsidiaries and variable interest entities where we are the primary
beneficiary. The equity method is used to account for investments in affiliates in which we have the
ability to exert significant influence over the affiliates’ operating and financial policies. When we do not
have the ability to exert significant influence, the investment is measured at fair value except when the
investment does not have a readily determinable fair value. For those exceptions, it will be measured at
cost minus impairment, plus or minus observable price changes in orderly transactions for an identical or
similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines, natural
gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are
generally carried at cost.
We manage our operations through six operating segments, defined by geographic region: Alaska, Lower
48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International. For
additional information, see Note 25—Segment Disclosures and Related Information.
Foreign Currency Translation—Adjustments resulting from the process of translating foreign
functional currency financial statements into U.S. dollars are included in accumulated other
comprehensive loss in common stockholders’ equity. Foreign currency transaction gains and losses are
included in current earnings. Some of our foreign operations use their local currency as the functional
currency.
Use of Estimates—The preparation of financial statements in conformity with accounting principles
generally accepted in the U.S. requires management to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and
liabilities. Actual results could differ from these estimates.
Revenue Recognition—Revenues associated with the sales of crude oil, bitumen, natural gas, LNG,
NGLs and other items are recognized at the point in time when the customer obtains control of the asset.
In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal
title and physical delivery has occurred, whether the customer has significant risks and rewards of
ownership, and whether the customer has accepted delivery and a right to payment exists. These products
are typically sold at prevailing market prices. We allocate variable market-based consideration to
deliveries (performance obligations) in the current period as that consideration relates specifically to our
efforts to transfer control of current period deliveries to the customer and represents the amount we
expect to be entitled to in exchange for the related products. Payment is typically due within 30 days or
less.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale
of inventory with the same counterparty are entered into “in contemplation” of one another, are combined
and reported net (i.e., on the same income statement line).
Shipping and Handling Costs—We typically incur shipping and handling costs prior to control
transferring to the customer and account for these activities as fulfillment costs. Accordingly, we include
shipping and handling costs in production and operating expenses for production activities.
Transportation costs related to marketing activities are recorded in purchased commodities. Freight costs
billed to customers are treated as a component of the transaction price and recorded as a component of
revenue when the customer obtains control.
Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily
convertible to known amounts of cash and have original maturities of 90 days or less from their date of
purchase. They are carried at cost plus accrued interest, which approximates fair value.
86
■
■
■
■
■
Short-Term Investments—Short-term investments include investments in bank time deposits and
marketable securities (commercial paper and government obligations) which are carried at cost plus
accrued interest and have original maturities of greater than 90 days but within one year or when the
remaining maturities are within one year. We also invest in financial instruments classified as available
for sale debt securities which are carried at fair value. Those instruments are included in short-term
investments when they have remaining maturities within one year as of the balance sheet date.
Long-Term Investments in Debt Securities—Long-term investments in debt securities includes
financial instruments classified as available for sale debt securities with remaining maturities greater than
one year as of the balance sheet date. They are carried at fair value and presented within the “Investments
and long-term receivables” line of our consolidated balance sheet.
Inventories—We have several valuation methods for our various types of inventories and consistently
use the following methods for each type of inventory. The majority of our commodity-related inventories
are recorded at cost using the LIFO basis. We measure these inventories at the lower-of-cost-or-market in
the aggregate. Any necessary lower-of-cost-or-market write-downs at year end are recorded as
permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with
current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or
product to its existing condition and location, but not unusual/nonrecurring costs or research and
development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and
well equipment, are valued using various methods, including the weighted-average-cost method, and the
FIFO method, consistent with industry practice.
Fair Value Measurements—Assets and liabilities measured at fair value and required to be categorized
within the fair value hierarchy are categorized into one of three different levels depending on the
observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active
markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices
included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated
inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications
to observable related market data or our assumptions about pricing by market participants.
Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the
right of offset exists and certain other criteria are met, derivative assets and liabilities with the same
counterparty are netted on the balance sheet and the collateral payable or receivable is netted against
derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to
fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives
not accounted for as hedges are recognized immediately in earnings.
■
Oil and Gas Exploration and Development—Oil and gas exploration and development costs are
accounted for using the successful efforts method of accounting.
Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in
the balance sheet caption PP&E. Leasehold impairment is recognized based on exploratory
experience and management’s judgment. Upon achievement of all conditions necessary for reserves
to be classified as proved, the associated leasehold costs are reclassified to proved properties.
Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or
“suspended,” on the balance sheet pending further evaluation of whether economically recoverable
reserves have been found. If economically recoverable reserves are not found, exploratory well costs
are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and
gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the
reserves and the economic and operating viability of the project is being made. For complex
exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance
87
sheet for several years while we perform additional appraisal drilling and seismic work on the
potential oil and gas field or while we seek government or co-venturer approval of development plans
or seek environmental permitting. Once all required approvals and permits have been obtained, the
projects are moved into the development phase, and the oil and gas resources are designated as proved
reserves.
Management reviews suspended well balances quarterly, continuously monitors the results of the
additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes
when it judges the potential field does not warrant further investment in the near term. See Note 8—
Suspended Wells and Other Exploration Expenses, for additional information on suspended wells.
Development Costs—Costs incurred to drill and equip development wells, including unsuccessful
development wells, are capitalized.
Depletion and Amortization—Leasehold costs of producing properties are depleted using the unit-
of-production method based on estimated proved oil and gas reserves. Amortization of intangible
development costs is based on the unit-of-production method using estimated proved developed oil
and gas reserves.
■
■
■
Capitalized Interest—Interest from external borrowings is capitalized on major projects with an
expected construction period of one year or longer. Capitalized interest is added to the cost of the
underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying
assets.
Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon
properties and certain pipeline and LNG assets (those which are expected to have a declining utilization
pattern), are determined by the unit-of-production method. Depreciation and amortization of all other
PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method
(for those individual units that are highly integrated with other units).
Impairment of Properties, Plants and Equipment—PP&E used in operations are assessed for
impairment whenever changes in facts and circumstances indicate a possible significant deterioration in
the future cash flows expected to be generated by an asset group and annually in the fourth quarter
following updates to corporate planning assumptions. If there is an indication the carrying amount of an
asset may not be recovered, the asset is monitored by management through an established process where
changes to significant assumptions such as prices, volumes and future development plans are reviewed.
If, upon review, the sum of the undiscounted before-tax cash flows is less than the carrying value of the
asset group, the carrying value is written down to estimated fair value through additional amortization or
depreciation provisions and reported as impairments in the periods in which the determination of the
impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which
there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—
generally on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices
for long-lived assets, the fair value of impaired assets is typically determined based on the present values
of expected future cash flows using discount rates believed to be consistent with those used by principal
market participants or based on a multiple of operating cash flow validated with historical market
transactions of similar assets where possible. Long-lived assets committed by management for disposal
within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair
value determined using a binding negotiated price, if available, or present value of expected future cash
flows as previously described.
The expected future cash flows used for impairment reviews and related fair value calculations are based
on estimated future production volumes, prices and costs, considering all available evidence at the date of
review. The impairment review includes cash flows from proved developed and undeveloped reserves,
including any development expenditures necessary to achieve that production. Additionally, when
probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be
included in the impairment calculation.
88
■
■
■
■
■
■
Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are
assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has
occurred and annually following updates to corporate planning assumptions. When such a condition is
judgmentally determined to be other than temporary, the carrying value of the investment is written down
to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or
upon the present value of expected future cash flows using discount rates believed to be consistent with
those used by principal market participants, plus market analysis of comparable assets owned by the
investee, if appropriate.
Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements,
are expensed when incurred.
Property Dispositions—When complete units of depreciable property are sold, the asset cost and related
accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line
of our consolidated income statement. When less than complete units of depreciable property are
disposed of or retired which do not significantly alter the DD&A rate, the difference between asset cost
and salvage value is charged or credited to accumulated depreciation.
Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire
and remove long-lived assets are recorded in the period in which the obligation is incurred (typically
when the asset is installed at the production location). When the liability is initially recorded, we
capitalize this cost by increasing the carrying amount of the related PP&E. If, in subsequent periods, our
estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Over time
the liability is increased for the change in its present value, and the capitalized cost in PP&E is
depreciated over the useful life of the related asset. Reductions to estimated liabilities for assets that are
no longer producing are recorded as a credit to impairment, if the asset had been previously impaired, or
as a credit to DD&A, if the asset had not been previously impaired. For additional information, see
Note 10—Asset Retirement Obligations and Accrued Environmental Costs.
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit.
Expenditures relating to an existing condition caused by past operations, and those having no future
economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an
undiscounted basis (unless acquired in a purchase business combination, which we record on a discounted
basis) when environmental assessments or cleanups are probable and the costs can be reasonably
estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when
their receipt is probable and estimable.
Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the
guarantee is given. The initial liability is subsequently reduced as we are released from exposure under
the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on
the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is
indefinite, we reverse the liability when we have information indicating the liability is essentially relieved
or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over
time. We amortize the guarantee liability to the related income statement line item based on the nature of
the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a
separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We
reverse the fair value liability only when there is no further exposure under the guarantee.
Share-Based Compensation—We recognize share-based compensation expense over the shorter of the
service period (i.e., the stated period of time required to earn the award) or the period beginning at the
start of the service period and ending when an employee first becomes eligible for retirement. We have
elected to recognize expense on a straight-line basis over the service period for the entire award, whether
the award was granted with ratable or cliff vesting.
■
Income Taxes—Deferred income taxes are computed using the liability method and are provided on all
temporary differences between the financial reporting basis and the tax basis of our assets and liabilities,
89
■
■
except for deferred taxes on income and temporary differences related to the cumulative translation
adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate
joint ventures. Allowable tax credits are applied currently as reductions of the provision for income
taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties
related to unrecognized tax benefits are reflected in production and operating expenses.
Taxes Collected from Customers and Remitted to Governmental Authorities—Sales and value-
added taxes are recorded net.
Net Income (Loss) Per Share of Common Stock—Basic net income (loss) per share of common stock
is calculated based upon the daily weighted-average number of common shares outstanding during the
year. Also, this calculation includes fully vested stock and unit awards that have not yet been issued as
common stock, along with an adjustment to net income (loss) for dividend equivalents paid on unvested
unit awards that are considered participating securities. Diluted net income per share of common stock
includes unvested stock, unit or option awards granted under our compensation plans and vested but
unexercised stock options, but only to the extent these instruments dilute net income per share, primarily
under the treasury-stock method. Diluted net loss per share, which is calculated the same as basic net loss
per share, does not assume conversion or exercise of securities that would have an antidilutive effect.
Treasury stock is excluded from the daily weighted-average number of common shares outstanding in
both calculations. The earnings per share impact of the participating securities is immaterial.
Note 2—Changes in Accounting Principles
We adopted the provisions of FASB ASU No. 2016-02, “Leases,” (ASC Topic 842) and its amendments,
beginning January 1, 2019. ASC Topic 842 establishes comprehensive accounting and financial reporting
requirements for leasing arrangements, supersedes the existing requirements in FASB ASC Topic 840,
“Leases” (ASC Topic 840), and requires lessees to recognize substantially all lease assets and lease liabilities
on the balance sheet. The provisions of ASC Topic 842 also modify the definition of a lease and outline
requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both
lessees and lessors.
We adopted ASC Topic 842 using the modified retrospective approach and elected to utilize the Optional
Transition Method, which permits us to apply the provisions of ASC Topic 842 to leasing arrangements
existing at or entered into after January 1, 2019, and present in our financial statements comparative periods
prior to January 1, 2019 under the historical requirements of ASC Topic 840. In addition, we elected to adopt
the package of optional transition-related practical expedients, which among other things, allows us to carry
forward certain historical conclusions reached under ASC Topic 840 regarding lease identification,
classification, and the accounting treatment of initial direct costs. Furthermore, we elected not to record assets
and liabilities on our consolidated balance sheet for new or existing lease arrangements with terms of 12
months or less.
The primary impact of applying ASC Topic 842 is the initial recognition of $998 million of lease liabilities and
corresponding right-of-use assets on our consolidated balance sheet as of January 1, 2019, for leases classified
as operating leases under ASC Topic 840, as well as enhanced disclosure of our leasing arrangements. Our
accounting treatment for finance leases remains unchanged. In addition, there is no cumulative effect to
retained earnings or other components of equity recognized as of January 1, 2019, and the adoption of ASC
Topic 842 did not impact the presentation of our consolidated income statement or statement of cash flows.
See Note 17—Non-Mineral Leases for additional information related to the adoption of ASC Topic 842.
90
We adopted the provisions of FASB ASU No. 2018-02, “Reclassification of Certain Tax Effects from
Accumulated Other Comprehensive Income,” beginning January 1, 2019. The ASU allows a reclassification
from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the
Tax Cuts and Jobs Act, eliminating the stranded tax effects. The cumulative effect to our consolidated balance
sheet at January 1, 2019 for the adoption of ASU No. 2018-02 was as follows:
Millions of Dollars
December 31 ASU No. 2018-02
Adjustments
2018
January 1
2019
Equity
Accumulated other comprehensive loss
Retained earnings
For additional information regarding the impact of the adoption of ASU No. 2018-02, see Note 20—Accumulated Other Comprehensive Loss.
(6,063)
34,010
(40)
40
(6,103)
34,050
$
Note 3—Variable Interest Entities
We hold variable interests in VIEs for which there are existing arrangements that provide those entities with
additional forms of subordinated financial support. However, as we are not considered the primary
beneficiary, these entities have not been consolidated in our financial statements.
Marine Well Containment Company, LLC (MWCC)
We have a 10 percent ownership interest in MWCC, and it is accounted for as an equity method investment
because MWCC is a limited liability company in which we are a founding member. MWCC is considered a
VIE, as it has entered into arrangements that provide it with additional forms of subordinated financial support.
We are not the primary beneficiary and do not consolidate MWCC because we share the power to govern the
business and operation of the company and to undertake certain obligations that most significantly impact its
economic performance with nine other unaffiliated owners of MWCC.
Based on inputs related to the fair value of MWCC observed in the second quarter of 2019, we reduced the
carrying value of our equity method investment in MWCC to $30 million and recorded a before-tax
impairment of $95 million which is included in the “Equity in earnings of affiliates” line on our consolidated
income statement. For additional information see Note 15—Fair Value Measurement. At December 31, 2019,
the book value of our equity method investment in MWCC was $24 million. We have not provided any
financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise,
we have no requirement to provide liquidity or purchase the assets of MWCC.
Australia Pacific LNG Pty Ltd (APLNG)
We hold a 37.5 percent interest in APLNG, our joint venture with Origin Energy and Sinopec. We are not the
primary beneficiary because we share, with our joint venture partners, the power to direct the key activities of
APLNG that most significantly impacts its economic performance. Therefore, we do not consolidate APLNG
and account for this entity as an equity method investment. As of December 31, 2019, we no longer have
certain guarantees that provide APLNG with additional subordinated financial support. For additional
information see Note 12—Guarantees.
91
Note 4—Inventories
Inventories at December 31 were:
Crude oil and natural gas
Materials and supplies
Millions of Dollars
2019
472
554
1,026
$
$
2018
432
575
1,007
Inventories valued on the LIFO basis totaled $286 million and $292 million at December 31, 2019 and 2018,
respectively. The estimated excess of current replacement cost over LIFO cost of inventories was
approximately $155 million and $75 million at December 31, 2019 and December 31, 2018, respectively.
Note 5—Asset Acquisitions and Dispositions
All gains or losses on asset dispositions are reported before-tax and are included net in the “Gain on
dispositions” line on our consolidated income statement. All cash proceeds are included in the “Cash Flows
From Investing Activities” section of our consolidated statement of cash flows.
2019
Assets Held for Sale
In October 2019, we entered into an agreement to sell the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary adjustments, with an effective date of January 1, 2019.
In addition, we will receive a payment of $75 million upon final investment decision of the Barossa
development project. These subsidiaries hold our 37.5 percent interest in the Barossa Project and Caldita
Field, our 56.9 percent interest in the Darwin LNG Facility and Bayu-Undan Field, our 40 percent interest in
the Greater Poseidon Fields, and our 50 percent interest in the Athena Field. The net carrying value is
approximately $0.6 billion, which consisted primarily of $1.2 billion of PP&E and $0.3 billion of cash and
working capital, offset by $0.7 billion of ARO and $0.2 billion of deferred tax liabilities. The assets met held
for sale criteria in the fourth quarter, and as of December 31, 2019 we had reclassified $1.2 billion of PP&E to
“Prepaid expenses and other current assets” and $0.7 billion of noncurrent ARO to “Other accruals” on our
consolidated balance sheet. The before-tax earnings associated with our Australia-West subsidiaries were
$372 million, $364 million and $317 million for the years ended December 31, 2019, 2018 and 2017,
respectively. This transaction is expected to be completed in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent. Results of operations for the subsidiaries to be sold are
reported within our Asia Pacific and Middle East segment.
In the fourth quarter of 2019, we signed an agreement to sell our interests in the Niobrara shale play for $380
million, plus customary adjustments, and overriding royalty interests in certain future wells. To reduce the
carrying value to fair value, in the fourth quarter of 2019, we recorded an impairment of $379 million before-
tax for developed properties and exploration expenses of $7 million related to leasehold impairment of
undeveloped properties. Our Niobrara interests to be sold have a net carrying value of approximately $390
million, which consisted primarily of $426 million of PP&E, offset by $34 million of noncurrent ARO. The
assets met held for sale criteria in the fourth quarter, and as of December 31, 2019, we had reclassified $426
million of PP&E to “Prepaid expenses and other current assets” and $34 million of noncurrent AROs to “Other
accruals” on our consolidated balance sheet. The before-tax losses associated with our interests in Niobrara,
including the $386 million of impairments noted above, were $372 million and $12 million for the years ended
December 31, 2019 and 2017, respectively. The before-tax earnings associated with our interests in Niobrara
for the year ended December 31, 2018 was $35 million. This transaction is subject to regulatory approval and
other specific conditions precedent and is expected to close in the first quarter of 2020. The Niobrara results of
operations are reported within our Lower 48 segment.
92
Assets Sold
In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the Golden Pass
LNG Terminal and Golden Pass Pipeline. We also entered into agreements to amend our contractual
obligations for retaining use of the facilities. As a result of entering into these agreements, we recorded a
before-tax impairment of $60 million in the first quarter of 2019 which is included in the “Equity in earnings
of affiliates” line on our consolidated income statement. We completed the sale in the second quarter of 2019.
Results of operations for these assets are reported in our Lower 48 segment. See Note 15—Fair Value
Measurement for additional information.
In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P
Limited for $2.675 billion plus interest and customary adjustments, with an effective date of January 1, 2018.
On September 30, 2019, we completed the sale for proceeds of $2.2 billion and recognized a $1.7 billion
before-tax and $2.1 billion after-tax gain associated with this transaction in 2019. Together the subsidiaries
sold indirectly held our exploration and production assets in the U.K. At the time of disposition, the net
carrying value was approximately $0.5 billion, consisting primarily of $1.6 billion of PP&E, $0.5 billion of
cumulative foreign currency translation adjustments, and $0.3 billion of deferred tax assets, offset by $1.8
billion of ARO and negative $0.1 billion of working capital. The before-tax earnings associated with the
subsidiaries sold were $0.4 billion, $0.9 billion and $0.3 billion for the years ended December 31, 2019, 2018
and 2017, respectively. Results of operations for the U.K. are reported within our Europe and North Africa
segment.
In the second quarter of 2019, we recognized an after-tax gain of $52 million upon the closing of the sale of
our 30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million. The
Greater Sunrise Fields were included in our Asia Pacific and Middle East segment.
In the fourth quarter of 2019, we sold our interests in the Magnolia field and platform for net proceeds of $16
million and recognized a before-tax gain of $82 million. At the time of sale, the net carrying value consisted
of $4 million of PP&E offset by $70 million of ARO. The Magnolia results of operations are reported within
our Lower 48 segment.
Planned Dispositions
In January 2020, we entered into an agreement to sell our interests in certain non-core properties in the Lower
48 segment for $186 million, plus customary adjustments. The assets met the held for sale criteria in January
2020 and the transaction is expected to be completed in the first quarter of 2020. No gain or loss is anticipated
on the sale. This disposition will not have a significant impact on Lower 48 production.
2018
Assets Sold
In the first quarter of 2018, we completed the sale of certain properties in the Lower 48 segment for net
proceeds of $112 million. No gain or loss was recognized on the sale. In the second quarter of 2018, we
completed the sale of a package of largely undeveloped acreage in the Lower 48 segment for net proceeds of
$105 million and no gain or loss was recognized on the sale. In the third quarter of 2018, we completed a
noncash exchange of undeveloped acreage in the Lower 48 segment. The transaction was recorded at fair
value resulting in the recognition of a $56 million gain. In the fourth quarter of 2018, we sold several
packages of undeveloped acreage in the Lower 48 segment for total net proceeds of $162 million and
recognized gains of approximately $140 million.
On October 31, 2018, we completed the sale of our interests in the Barnett to Lime Rock Resources for $196
million after customary adjustments and recognized a loss of $5 million. We recorded impairments of $87
million in 2018 and $572 million in 2017 to reduce the net carrying value of the Barnett to fair value. At the
time of the disposition, our interest in Barnett had a net carrying value of $201 million, consisting of $250
million of PP&E and $49 million of AROs. The before-tax losses associated with our interests in the Barnett,
including both the impairments and loss on disposition noted above, were $59 million and $566 million for the
years 2018 and 2017, respectively. The Barnett results of operations are included in our Lower 48 segment.
93
On December 18, 2018, we completed the sale of a ConocoPhillips subsidiary to BP. The subsidiary held
16.5 percent of our 24 percent interest in the BP-operated Clair Field in the U.K. We retained a 7.5 percent
interest in the field. At the same time, we acquired BP’s 39.2 percent nonoperated interest in the Greater
Kuparuk Area in Alaska, including their 38 percent interest in the Kuparuk Transportation Company (Kuparuk
Assets). The transaction was recorded at a fair value of $1,743 million and was cash neutral except for
customary adjustments which resulted in net proceeds of $253 million. At closing, our interest in the Clair
Field had a net carrying value of approximately $1,028 million consisting primarily of $1,553 million of
PP&E, $485 million of deferred tax liabilities, and $59 million of AROs. We recognized a before-tax gain of
$715 million on the transaction. The 2018 before-tax earnings associated with our 16.5 interest in the Clair
Field, including the recognized gain, were $748 million. The before-tax loss associated with our interest in the
Clair Field was $0.4 million for 2017. Results of operations for our interest in the Clair Field are reported
within our Europe and North Africa segment and the Kuparuk Assets are included in our Alaska segment.
Acquisitions
In May 2018, we completed the acquisition of Anadarko’s 22 percent nonoperated interest in the Western
North Slope of Alaska, as well as its interest in the Alpine Transportation Pipeline for $386 million, after
customary adjustments. This transaction was accounted for as a business combination resulting in the
recognition of approximately $297 million of proved property and $114 million of unproved property within
PP&E, $20 million of inventory, $14 million of investments, and $59 million of AROs. These assets are
included in our Alaska segment.
As discussed in the Clair Field transaction with BP above, we acquired BP’s Kuparuk Assets on December 18,
2018. The transaction was accounted for as an asset acquisition with a net acquisition cost of $1,490 million,
comprised of the fair value of $1,743 million associated with the disposed 16.5 percent of our 24 percent
interest in the Clair Field, reduced by the net proceeds of $253 million. Accordingly, we recorded
approximately $1.9 billion to proved property within PP&E, $42 million to inventory, $15 million to
investments, $374 million of AROs, and a $100 million decrease to net working capital. The Kuparuk Assets
are included in our Alaska segment.
2017
Assets Sold
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the Foster Creek Christina
Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy.
Consideration for the transaction was $11.0 billion in cash after customary adjustments, 208 million Cenovus
Energy common shares and a five-year uncapped contingent payment. The value of the shares at closing was
$1.96 billion based on a price of $9.41 per share on the NYSE. The contingent payment, calculated and paid
on a quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price
exceeds $52 CAD per barrel. Contingent payments received during the five-year period are reflected as “Gain
on dispositions” on our consolidated income statement. We reported before-tax equity earnings associated
with FCCL of $197 million for 2017. We reported a before-tax loss of $26 million for the western Canada gas
producing properties for 2017. We recorded gains on dispositions for these contingent payments of $114
million and $95 million for the years 2019 and 2018, respectively.
At closing, the carrying value of our equity investment in FCCL was $8.9 billion. The carrying value of our
interest in the western Canada gas assets was $1.9 billion consisting primarily of $2.6 billion of PP&E, partly
offset by AROs of $585 million and approximately $100 million of environmental and other accruals. A gain
of $2.1 billion was included in the “Gain on dispositions” line on our consolidated income statement in 2017.
Both FCCL and the western Canada gas assets were reported in our Canada segment.
For more information on the Canada disposition and our investment in Cenovus Energy see Note 7—
Investment in Cenovus Energy, Note 15—Fair Value Measurement, and Note 20—Accumulated Other
Comprehensive Loss.
In July 2017, we completed the sale of our interests in the San Juan Basin to an affiliate of Hilcorp Energy
94
Company for $2.5 billion in cash after customary adjustments and recognized a loss on disposition of
$22 million. The transaction includes a contingent payment of up to $300 million. The six-year contingent
payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly U.S. Henry
Hub price is at or above $3.20 per MMBTU. In 2018, we recorded a gain on dispositions for these contingent
payments of $28 million. No contingent payments were recorded in 2019. In the second quarter of 2017, we
recorded an impairment of $3.3 billion to reduce the carrying value of our interests in the San Juan Basin to
fair value. At the time of disposition, the San Juan Basin interests had a net carrying value of approximately
$2.5 billion, consisting of $2.9 billion of PP&E and $406 million of liabilities, primarily AROs. The before-
tax loss associated with our interests in the San Juan Basin, including both the $3.3 billion impairment and $22
million loss on disposition noted above, was $3.2 billion for 2017. The San Juan Basin results were reported
in our Lower 48 segment.
In September 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash after
customary adjustments and recognized a loss on disposition of $28 million. At the time of the disposition, the
carrying value of our interest was $206 million, consisting primarily of $279 million of PP&E and $72 million
of AROs. Including the $28 million loss on disposition noted above, we reported a before-tax loss for the
Panhandle properties of $14 million for 2017. The Panhandle results were reported in our Lower 48 segment.
Note 6—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Equity investments
Loans and advances—related parties
Long-term receivables
Long-term investments in debt securities
Other investments
Millions of Dollars
2019
2018
$
$
8,234
219
243
133
77
8,906
9,005
335
238
-
86
9,664
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2019, included:
●
●
APLNG—37.5 percent owned joint venture with Origin Energy (37.5 percent) and Sinopec (25 percent)—
to produce CBM from the Bowen and Surat basins in Queensland, Australia, as well as process and export
LNG.
Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned joint venture with affiliates of Qatar
Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from
Qatar’s North Field, as well as exports LNG.
Summarized 100 percent earnings information for equity method investments in affiliated companies,
combined, was as follows:
Revenues
Income (loss) before income taxes
Net income (loss)
95
Millions of Dollars
2019
2018
2017
$
11,310
3,726
3,085
11,654
3,660
3,244
11,554
(2,875)
(1,431)
Summarized 100 percent balance sheet information for equity method investments in affiliated companies,
combined, was as follows:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Millions of Dollars
2019
2018
$
3,289
38,905
2,603
22,168
3,285
41,563
2,625
23,874
Our share of income taxes incurred directly by an equity method investee is reported in equity in earnings of
affiliates, and as such is not included in income taxes on our consolidated financial statements.
At December 31, 2019, retained earnings included $32 million related to the undistributed earnings of
affiliated companies. Dividends received from affiliates were $1,378 million, $1,226 million and $605 million
in 2019, 2018 and 2017, respectively.
APLNG
APLNG is focused on CBM production from the Bowen and Surat basins in Queensland, Australia, to supply
the domestic gas market and on LNG processing and export sales. Our investment in APLNG gives us access
to CBM resources in Australia and enhances our LNG position. The majority of APLNG LNG is sold under
two long-term sales and purchase agreements, supplemented with sales of additional LNG spot cargoes
targeting the Asia Pacific markets. Origin Energy, an integrated Australian energy company, is the operator of
APLNG’s production and pipeline system, while we operate the LNG facility.
APLNG executed project financing agreements for an $8.5 billion project finance facility in 2012. The $8.5
billion project finance facility was initially composed of financing agreements executed by APLNG with the
Export-Import Bank of the United States for approximately $2.9 billion, the Export-Import Bank of China for
approximately $2.7 billion, and a syndicate of Australian and international commercial banks for
approximately $2.9 billion. At December 31, 2019, all amounts have been drawn from the facility. APLNG
made its first principal and interest repayment in March 2017 and is scheduled to make bi-annual payments
until March 2029.
APLNG made a voluntary repayment of $1.4 billion to the Export-Import Bank of China in September 2018.
At the same time, APLNG obtained a United States Private Placement (USPP) bond facility of $1.4 billion.
APLNG made its first interest payment related to this facility in March 2019, and principal payments are
scheduled to commence in September 2023, with bi-annual payments due on the facility until September 2030.
During the first quarter of 2019, APLNG refinanced $3.2 billion of existing project finance debt through two
transactions. As a result of the first transaction, APLNG obtained a commercial bank facility of $2.6 billion.
APLNG made its first principal and interest repayment in September 2019 with bi-annual payments due on the
facility until March 2028. Through the second transaction, APLNG obtained a USPP bond facility of $0.6
billion. APLNG made its first interest payment in September 2019, and principal payments are scheduled to
commence in September 2023, with bi-annual payments due on the facility until September 2030.
In conjunction with the $3.2 billion debt obtained during the first quarter of 2019 to refinance existing project
finance debt, APLNG made voluntary repayments of $2.2 billion and $1.0 billion to a syndicate of Australian
and international commercial banks and the Export-Import Bank of China, respectively.
At December 31, 2019, a balance of $6.7 billion was outstanding on the facilities. See Note 12—Guarantees,
for additional information.
96
During the first half of 2017, the outlook for crude oil prices deteriorated, and as a result of significantly
reduced price outlooks, the estimated fair value of our investment in APLNG declined to an amount below
carrying value. Based on a review of the facts and circumstances surrounding this decline in fair value, we
concluded in the second quarter of 2017 the impairment was other than temporary under the guidance of FASB
ASC Topic 323, “Investments—Equity Method and Joint Ventures,” and the recognition of an impairment of
our investment to fair value was necessary. Accordingly, we recorded a noncash $2,384 million, before- and
after-tax impairment in our second quarter 2017 results. Fair value was estimated based on an internal
discounted cash flow model using estimated future production, an outlook of future prices from a combination
of exchanges (short-term) and pricing service companies (long-term), costs, a market outlook of foreign
exchange rates provided by a third party, and a discount rate believed to be consistent with those used by
principal market participants. The impairment was included in the “Impairments” line on our consolidated
income statement.
At December 31, 2019, the carrying value of our equity method investment in APLNG was $7,228 million.
The historical cost basis of our 37.5 percent share of net assets on the books of APLNG was $6,751 million,
resulting in a basis difference of $477 million on our books. The basis difference, which is substantially all
associated with PP&E and subject to amortization, has been allocated on a relative fair value basis to
individual exploration and production license areas owned by APLNG, some of which are not currently in
production. Any future additional payments are expected to be allocated in a similar manner. Each
exploration license area will periodically be reviewed for any indicators of potential impairment, which, if
required, would result in acceleration of basis difference amortization. As the joint venture produces natural
gas from each license, we amortize the basis difference allocated to that license using the unit-of-production
method. Included in net income (loss) attributable to ConocoPhillips for 2019, 2018 and 2017 was after-tax
expense of $36 million, $44 million and $100 million, respectively, representing the amortization of this basis
difference on currently producing licenses.
Distributions from APLNG commenced in April 2018.
FCCL
FCCL Partnership, a Canadian upstream 50/50 general partnership with Cenovus Energy Inc., produces
bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend. Cenovus is the
operator and managing partner of FCCL.
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets to Cenovus Energy. Financial information presented
within this footnote includes our historical interest up to the date of sale. For additional information on the
Canada disposition and our investment in Cenovus Energy, see Note 5—Asset Acquisitions and Dispositions
and Note 7—Investment in Cenovus Energy.
QG3
QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project
financing, with a current outstanding balance of $335 million as described below under “Loans and Long-
Term Receivables.” At December 31, 2019, the book value of our equity method investment in QG3,
excluding the project financing, was $797 million. We have terminal and pipeline use agreements with Golden
Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with
terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. We
previously held a 12.4 percent interest in Golden Pass LNG Terminal and Golden Pass Pipeline, but we sold
those interests in the second quarter of 2019 while retaining the basic use agreements. Currently, the LNG
from QG3 is being sold to markets outside of the U.S. For additional information, see Note 5—Asset
Acquisitions and Dispositions.
97
Loans and Long-Term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter into
numerous agreements with other parties to pursue business opportunities. Included in such activity are loans
and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is
transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan
agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will
decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated
interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan
balance may not be fully recovered.
At December 31, 2019, significant loans to affiliated companies include $335 million in project financing to
QG3. We own a 30 percent interest in QG3, for which we use the equity method of accounting. The other
participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of
$4.0 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5
billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have
substantially the same terms as the ECA and commercial bank facilities. On December 15, 2011, QG3
achieved financial completion and all project loan facilities became nonrecourse to the project participants.
Semi-annual repayments began in January 2011 and will extend through July 2022.
The long-term portion of these loans is included in the “Loans and advances—related parties” line on our
consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”
Note 7—Investment in Cenovus Energy
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets, to Cenovus Energy. Consideration for the transaction
included 208 million Cenovus Energy common shares, which, at closing, approximated 16.9 percent of issued
and outstanding Cenovus Energy common stock. See Note 5—Asset Acquisitions and Dispositions, for
additional information on the Canada disposition. The fair value and cost basis of our investment in 208
million Cenovus Energy common shares was $1.96 billion based on a price of $9.41 per share on the NYSE on
the closing date.
Our investment on our consolidated balance sheet as of December 31, 2019, is carried at fair value of $2.11
billion, reflecting the closing price of Cenovus Energy shares on the NYSE of $10.15 per share, an increase of
$649 million from $1.46 billion at December 31, 2018. The increase in fair value represents the net unrealized
gain recorded within the “Other income” line of our consolidated income statement for the year ended
December 31, 2019 relating to the shares held at the reporting date. See Note 15—Fair Value Measurement
and Note 22—Other Financial Information, for additional information. Subject to market conditions, we
intend to decrease our investment over time through market transactions, private agreements or otherwise.
98
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:
Beginning balance at January 1
Additions pending the determination of proved reserves
Reclassifications to proved properties
Sales of suspended wells
Charged to dry hole expense
Ending balance at December 31
*Includes $313 million of assets held for sale in Australia.
Millions of Dollars
2019
2018
2017
$
$
856
239
(11)
(54)
(10)
1,020 *
853
140
(37)
(93)
(7)
856
1,063
118
(66)
-
(262)
853
The following table provides an aging of suspended well balances at December 31:
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 $313 million of assets held for sale in Australia.
$
$
Millions of Dollars
2019
2018
2017
206
814
1,020 *
23
145
711
856
24
67
786
853
23
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
2016–2018
Suspended Since
2013–2015
2004–2012
-
111
59
6
-
52
-
-
17
20
265
157
38
-
55
68
-
19
11
-
26
374
20
-
77
57
-
-
-
4
-
17
175
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.
$
Total
177
149
136
118
68
52
19
15
17
63
814
99
Other Exploration Expenses
In February 2017, we reached a settlement agreement on our contract for the Athena drilling rig, initially
secured for our four-well commitment program in Angola. As a result of the cancellation, we recognized a
before-tax charge of $43 million net in the first quarter of 2017. These charges are included in the
“Exploration expenses” line on our consolidated income statement and in our Other International segment in
2017.
In 2019, we recorded before-tax dry hole expenses of $111 million due to our decision to discontinue
exploration activities in the Central Louisiana Austin Chalk trend. These charges are included in our Lower 48
segment and in the “Exploration expenses” line on our consolidated income statement. See Note 9—
Impairments for additional information on our decision to discontinue these exploration activities.
Note 9—Impairments
During 2019, 2018 and 2017, we recognized the following before-tax impairment charges:
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Millions of Dollars
2019
2018
2017
$
$
-
402
2
1
-
405
20
63
9
(79)
14
27
180
3,969
22
46
2,384
6,601
2019
In the Lower 48, we recorded impairments of $402 million, primarily related to developed properties in our
Niobrara asset which were written down to fair value less costs to sell. See Note 5—Asset Acquisitions and
Dispositions, for additional information on this disposition.
The charges discussed below, within this section, are included in the “Exploration expenses” line on our
consolidated income statement and are not reflected in the table above.
In our Lower 48 segment, we recorded a before-tax impairment of $141 million for the associated carrying
value of capitalized undeveloped leasehold costs due to our decision to discontinue exploration activities
related to our Central Louisiana Austin Chalk acreage.
2018
In Alaska, we recorded impairments of $20 million primarily due to cancelled projects.
In the Lower 48, we recorded impairments of $63 million, primarily related to developed properties in our
Barnett asset which were written down to fair value less costs to sell, partly offset by a revision to reflect
finalized proceeds on a separate transaction.
In our Europe and North Africa segment, we recorded a credit to impairment of $79 million, primarily due to
decreased ARO estimates on fields in the U.K. which have ceased production and were impaired in prior years,
partly offset by an increased ARO estimate on a field in Norway which has ceased production.
100
2017
In Alaska, we recorded impairments of $180 million primarily for the associated PP&E carrying value of our
small interest in the Point Thomson unit.
In the Lower 48, we recorded impairments of $3,969 million primarily due to certain developed properties
which were written down to fair value less costs to sell. See Note 5—Asset Acquisitions and Dispositions, for
additional information on our dispositions.
In Canada, we recorded impairments of $22 million primarily due to cancelled projects.
In Europe and North Africa, we recorded impairments of $46 million primarily due to reduced volume
forecasts for a field in the U.K. and restructured ownership and a change in commercial premises for a gas
processing plant in Norway, partly offset by decreased ARO estimates on fields at or nearing the end of life
which were impaired in prior years.
In Asia Pacific and Middle East, we recorded impairments of $2,384 million, including the impairment of our
APLNG investment. For more information, see the “APLNG” section of Note 6—Investments, Loans and
Long-Term Receivables.
The charges discussed below, within this section, are included in the “Exploration expenses” line on our
consolidated income statement and are not reflected in the table above.
In our Lower 48 segment, we recorded a before-tax impairment of $51 million for the associated carrying
value of capitalized undeveloped leasehold costs of Shenandoah in deepwater Gulf of Mexico following the
suspension of appraisal activity by the operator. Additionally, we recorded a $38 million before-tax
impairment for mineral assets primarily due to plan of development changes.
Note 10—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Millions of Dollars
2019
2018
Asset retirement obligations
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
Asset retirement obligations and accrued environmental costs due within one year*
Long-term asset retirement obligations and accrued environmental costs
*Classified as a current liability on the balance sheet under “Other accruals.” $741 million relates to assets which are held for sale as of
December 31, 2019. For additional information see Note 5—Asset Acquisitions and Dispositions.
6,206
171
6,377
(1,025)
5,352
$
$
7,908
178
8,086
(398)
7,688
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.
101
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:
Balance at January 1
Accretion of discount
New obligations
Changes in estimates of existing obligations
Spending on existing obligations
Property dispositions
Foreign currency translation
Balance at December 31
Millions of Dollars
2019
2018
$
$
7,908
322
155
50
(229)
(1,920)
(80)
6,206
7,798
348
657
(266)
(228)
(161)
(240)
7,908
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2019 and 2018, were $171 million and $178 million,
respectively.
We had accrued environmental costs of $112 million and $100 million at December 31, 2019 and 2018,
respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and
Other $47 million and $67 million of environmental costs associated with sites no longer in operation at
December 31, 2019 and 2018, respectively. In addition, $12 million and $11 million were included at both
December 31, 2019 and 2018, respectively, where the company has been named a potentially responsible party
under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state
laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.
Expected expenditures for environmental obligations acquired in various business combinations are discounted
using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental
liabilities of $97 million at December 31, 2019. The expected future undiscounted payments related to the
portion of the accrued environmental costs that have been discounted are: $10 million in 2020, $7 million in
2021, $10 million in 2022, $3 million in 2023, $2 million in 2024, and $108 million for all future years
after 2024.
102
Note 11—Debt
Long-term debt at December 31 was:
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 2.81% – 3.58% during 2019 and
2.32% – 3.52% during 2018
Industrial Development Bonds due 2035 at 1.08% – 2.45% during 2019 and
0.95% – 1.86% during 2018
Marine Terminal Revenue Refunding Bonds due 2031 at 1.08% – 2.45% during
2019 and 0.88% – 1.95% during 2018
Other
Debt at face value
Finance leases
Net unamortized premiums, discounts and debt issuance costs
Total debt
Short-term debt
Long-term debt
$
Millions of Dollars
2019
2018
123
134
390
60
203
78
500
92
500
575
200
1,549
67
2,750
645
500
500
505
600
1,250
750
246
426
199
329
500
18
123
134
390
60
203
78
500
92
500
575
200
1,549
67
2,750
645
500
500
505
600
1,250
750
246
426
199
329
500
18
265
17
13,971
720
204
14,895
(105)
14,790
265
17
13,971
777
220
14,968
(112)
14,856
$
103
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2020 through
2024 are: $105 million, $235 million, $940 million, $198 million and $548 million, respectively.
We have a revolving credit facility totaling $6.0 billion with an expiration date of May 2023. Our revolving
credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500
million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated
among financial institutions and does not contain any material adverse change provisions or any covenants
requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-
default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or
more by ConocoPhillips, or any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight federal funds rate or prime rates offered by
certain designated banks in the U.S. The agreement calls for commitment fees on available, but unused,
amounts. The agreement also contains early termination rights if our current directors or their approved
successors cease to be a majority of the Board of Directors.
We have a $6.0 billion commercial paper program, which is primarily a funding source for short-term working
capital needs. Commercial paper maturities are generally limited to 90 days. We had no commercial paper
outstanding in programs in place at December 31, 2019 or December 31, 2018. We had no direct outstanding
borrowings or letters of credit under the revolving credit facility at December 31, 2019 or December 31, 2018.
Since we had no commercial paper outstanding and had issued no letters of credit, we had access to
$6.0 billion in borrowing capacity under our revolving credit facility at December 31, 2019.
At both December 31, 2019 and 2018, we had $283 million of certain variable rate demand bonds (VRDBs)
outstanding which mature in 2035. The VRDBs are redeemable at the option of the bondholders on any
business day. If they are ever redeemed, we intend to refinance on a long-term basis, therefore, the VRDBs are
included in the “Long-term debt” line on our consolidated balance sheet.
For additional information on Finance Leases, see Note 17—Non-Mineral Leases.
Note 12—Guarantees
At December 31, 2019, we were liable for certain contingent obligations under various contractual
arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as
a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted
below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition,
unless otherwise stated, we are not currently performing with any significance under the guarantee and expect
future performance to be either immaterial or have only a remote chance of occurrence.
APLNG Guarantees
At December 31, 2019, we had outstanding multiple guarantees in connection with our 37.5 percent ownership
interest in APLNG. The following is a description of the guarantees with values calculated utilizing December
2019 exchange rates:
• During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata
portion of the funds in a project finance reserve account. We estimate the remaining term of this
guarantee is 11 years. Our maximum exposure under this guarantee is approximately $170 million
and may become payable if an enforcement action is commenced by the project finance lenders
against APLNG. At December 31, 2019, the carrying value of this guarantee is approximately $14
million.
104
•
In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in
October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability
arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales
agreements with remaining terms of up to 22 years. Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated to be $780 million ($1.4
billion in the event of intentional or reckless breach) and would become payable if APLNG fails to
meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future
payments are considered unlikely, as the payments, or cost of volume delivery, would only be
triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-
venturers do not make necessary equity contributions into APLNG.
• We have guaranteed the performance of APLNG with regard to certain other contracts executed in
connection with the project’s continued development. The guarantees have remaining terms of up to
26 years or the life of the venture. As of December 31, 2019, we were released from certain of these
guarantees considered subordinated financial support to APLNG. Our remaining maximum potential
amount of future payments related to the remaining guarantees is approximately $60 million and
would become payable if APLNG does not perform.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately
$820 million, which consist primarily of guarantees of the residual value of leased office buildings, guarantees
of the residual value of leased corporate aircraft, and a guarantee for our portion of a joint venture’s project
finance reserve accounts. These guarantees have remaining terms of up to three years and would become
payable if, upon sale, certain asset values are lower than guaranteed amounts, business conditions decline at
guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties.
In conjunction with the disposition of our two U.K. subsidiaries to Chrysaor E&P Limited, we will temporarily
continue to support various guarantees and letters of credit which were provided for the benefit of entities that
are now affiliates of Chrysaor E&P Limited. Our maximum potential payment exposure under these
obligations is approximately $100 million. Chrysaor E&P Limited has agreed to fully indemnify
ConocoPhillips for any losses suffered by us related to these obligations.
Indemnifications
Over the years, we have entered into agreements to sell ownership interests in certain corporations, joint
ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications
for taxes, environmental liabilities, employee claims and litigation. The terms of these indemnifications vary
greatly. The majority of these indemnifications are related to environmental issues, the term is generally
indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded
for these indemnifications at December 31, 2019, was approximately $80 million. We amortize the
indemnification liability over the relevant time period, if one exists, based on the facts and circumstances
surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the
liability when we have information the liability is essentially relieved or amortize the liability over an
appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably
possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not
possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the
recorded carrying amount at December 31, 2019, were approximately $30 million of environmental accruals
for known contamination that are included in the “Asset retirement obligations and accrued environmental
costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see
Note 13—Contingencies and Commitments.
105
Note 13—Contingencies and Commitments
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed
against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the
placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active
and inactive sites. We regularly assess the need for accounting recognition or disclosure of these
contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a
liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be
reasonably estimated and no amount within the range is a better estimate than any other amount, then the
minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party
recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With
respect to income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases
where sustaining a tax position is less than certain. See Note 19—Income Taxes, for additional information
about income tax-related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent
liability exposures will exceed current accruals by an amount that would have a material adverse impact on our
consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position
both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future
changes include contingent liabilities recorded for environmental remediation, tax and legal matters.
Estimated future environmental remediation costs are subject to change due to such factors as the uncertain
magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and
the determination of our liability in proportion to that of other responsible parties. Estimated future costs
related to tax and legal matters are subject to change as events evolve and as additional information becomes
available during the administrative and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When we prepare
our consolidated financial statements, we record accruals for environmental liabilities based on management’s
best estimates, using all information that is available at the time. We measure estimates and base liabilities on
currently available facts, existing technology, and presently enacted laws and regulations, taking into account
stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior
experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by
the U.S. EPA or other organizations. We consider unasserted claims in our determination of environmental
liabilities, and we accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and
several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a
particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to
any site at which we have been designated as a potentially responsible party. We have been successful to date
in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially
responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those
potentially responsible normally assess the site conditions, apportion responsibility and determine the
appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability.
Where it appears that other potentially responsible parties may be financially unable to bear their proportional
share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.
As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these
environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the
indemnifications are subject to dollar limits and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and
comparable state and international sites. After an assessment of environmental exposures for cleanup and
other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business
combination, which we record on a discounted basis) for planned investigation and remediation activities for
sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have
106
not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional
environmental assessments, cleanups and proceedings. See Note 10—Asset Retirement Obligations and
Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
Legal Proceedings
We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty
and severance tax payments, gas measurement and valuation methods, contract disputes, environmental
damages, climate change, personal injury, and property damage. Our primary exposures for such matters
relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties and
claims of alleged environmental contamination from historic operations. We will continue to defend ourselves
vigorously in these matters.
Our legal organization applies its knowledge, experience and professional judgment to the specific
characteristics of our cases, employing a litigation management process to manage and monitor the legal
proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in
individual cases. This process also enables us to track those cases that have been scheduled for trial and/or
mediation. Based on professional judgment and experience in using these litigation management tools and
available information about current developments in all our cases, our legal organization regularly assesses the
adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new
accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies
not associated with financing arrangements. Under these agreements, we may be required to provide any such
company with additional funds through advances and penalties for fees related to throughput capacity not
utilized. In addition, at December 31, 2019, we had performance obligations secured by letters of credit of
$277 million (issued as direct bank letters of credit) related to various purchase commitments for materials,
supplies, commercial activities and services incident to the ordinary conduct of business.
In 2007, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated
by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company,
Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’
interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In
response to this expropriation, ConocoPhillips initiated international arbitration on November 2, 2007, with the
ICSID. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated
ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the
decision that the expropriation was unlawful. In March 2019, the Tribunal unanimously ordered the
government of Venezuela to pay ConocoPhillips approximately $8.7 billion in compensation for the
government’s unlawful expropriation of the company’s investments in Venezuela in 2007. ConocoPhillips has
filed a request for recognition of the award in several jurisdictions. On August 29, 2019, the ICSID Tribunal
issued a decision rectifying the award and reducing it by approximately $227 million. The award now stands
at $8.5 billion plus interest. The government of Venezuela sought annulment of the award.
In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against
PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued
an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $2 billion under their
agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In
August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC
award, plus interest through the payment period, including initial payments totaling approximately $500
million within a period of 90 days from the time of signing of the settlement agreement. The balance of the
settlement is to be paid quarterly over a period of four and a half years. To date, ConocoPhillips has received
approximately $754 million. Per the settlement, PDVSA recognized the ICC award as a judgment in various
jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices
of default to PDVSA on October 14 and November 12, 2019, and to date PDVSA failed to cure its breach. As
a result, ConocoPhillips has resumed legal enforcement actions. ConocoPhillips has ensured that the
107
settlement and any actions thereof meet all appropriate U.S. regulatory requirements, including those related to
any applicable sanctions imposed by the U.S. against Venezuela.
In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against
PDVSA under the contracts that had established the Corocoro project. On August 2, 2019, the ICC Tribunal
awarded ConocoPhillips approximately $55 million under the Corocoro contracts. ConocoPhillips is seeking
recognition and enforcement of the award in various jurisdictions. ConocoPhillips has ensured that all the
actions related to the award meet all appropriate U.S. regulatory requirements, including those related to any
applicable sanctions imposed by the U.S. against Venezuela.
In February 2017, the ICSID Tribunal unanimously awarded Burlington Resources, Inc., a wholly owned
subsidiary of ConocoPhillips, $380 million for Ecuador’s unlawful expropriation of Burlington’s investment in
Blocks 7 and 21, in breach of the U.S.-Ecuador Bilateral Investment Treaty. The tribunal also issued a
separate decision finding Ecuador to be entitled to $42 million for environmental and infrastructure
counterclaims. In December 2017, Burlington and Ecuador entered into a settlement agreement by which
Ecuador paid Burlington $337 million in two installments. The first installment of $75 million was paid in
December 2017, and the second installment of $262 million was paid in April 2018. The settlement included
an offset for the counterclaims decision, of which Burlington is entitled to a contribution from Perenco
Ecuador Limited, its co-venturer and consortium operator, pursuant to a joint and several liability provision in
the JOA. In September 2019, a separate ICSID Tribunal issued an award in the Perenco arbitration, ordering
Perenco to pay an additional $54 million to Ecuador for its environmental counterclaim. Burlington and
Perenco will reconcile their shares of the environmental and infrastructure counterclaims according to their
JOA participating interests, and we expect Burlington’s share will be immaterial.
In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V. in connection
with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016. In
February 2020, the ICC Tribunal issued an award dismissing FAR Ltd.’s claims in the arbitration.
In late 2017, ConocoPhillips (U.K.) Limited (CPUKL) initiated United Nations Commission on International
Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral
Investment Treaty relating to a tax dispute arising from the 2012 sale of ConocoPhillips (U.K.) Cuu Long
Limited and ConocoPhillips (U.K.) Gama Limited. The parties entered into a settlement agreement in October
2019, and the arbitration was dismissed in December 2019 as a result of this agreement.
In 2017 and 2018, cities, counties, and a state government in California, New York, Washington, Rhode Island
and Maryland, as well as the Pacific Coast Federation of Fishermen’s Association, Inc., have filed lawsuits
against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief
to abate alleged climate change impacts. ConocoPhillips is vigorously defending against these lawsuits. The
lawsuits brought by the Cities of San Francisco, Oakland and New York have been dismissed by the district
courts and appeals are pending. Lawsuits filed by other cities and counties in California and Washington are
currently stayed pending resolution of the appeals brought by the Cities of San Francisco and Oakland to the
U.S. Court of Appeals for the Ninth Circuit. Lawsuits filed in Maryland and Rhode Island are proceeding in
state court while rulings in those matters, on the issue of whether the matters should proceed in state or federal
court, are on appeal to the U.S. Court of Appeals for the Fourth Circuit and First Circuit, respectively.
Several Louisiana parishes and individual landowners have filed lawsuits against oil and gas companies,
including ConocoPhillips, seeking compensatory damages in connection with historical oil and gas operations
in Louisiana. All parish lawsuits are stayed pending an appeal to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or state court. ConocoPhillips will vigorously defend against
these lawsuits.
108
Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of financing arrangements.
The agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of
the company’s business. The aggregate amounts of estimated payments under these various agreements are:
2020—$7 million; 2021—$7 million; 2022—$7 million; 2023—$7 million; 2024—$7 million; and 2025 and
after—$57 million. Total payments under the agreements were $25 million in 2019, $39 million in 2018 and
$43 million in 2017.
Note 14—Derivative and Financial Instruments
We use futures, forwards, swaps and options in various markets to meet our customer needs and capture
market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and
NGLs.
Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have
the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on
our consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains
and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held
for trading. Gains and losses related to contracts that meet and are designated with the NPNS exception are
recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use
hedge accounting for our commodity derivatives.
The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the
line items where they appear on our consolidated balance sheet:
Assets
Prepaid expenses and other current assets
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
$
Millions of Dollars
2019
288
34
283
28
2018
410
40
370
30
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our
consolidated income statement were:
Sales and other operating revenues
Other income
Purchased commodities
Millions of Dollars
2019
2018
2017
$
141
4
(118)
45
7
(41)
77
-
(61)
109
The table below summarizes our material net exposures resulting from outstanding commodity derivative
contracts:
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
Basis
Open Position
Long/(Short)
2019
2018
(5)
(23)
(17)
(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:
Assets
Prepaid expenses and other current assets
Liabilities
Other accruals
Other liabilities and deferred credits
Millions of Dollars
2019
2018
$
1
20
8
7
6
-
The losses from foreign currency exchange derivatives incurred and the line item where they appear on our
consolidated income statement were:
Millions of Dollars
2019
2018
2017
Foreign currency transaction losses
$
16
1
13
We had the following net notional position of outstanding foreign currency exchange derivatives:
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy British pound
Sell British pound, buy other currencies*
Buy British pound, sell euro
Sell Canadian dollar, buy U.S. dollar
*Primarily euro and Norwegian krone.
In Millions
Notional Currency
2019
2018
USD
GBP
GBP
CAD
-
-
4
1,337
805
21
-
1,242
110
In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion
CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar.
The collar expired during the second quarter of 2019 and we entered into new foreign currency exchange
forward contracts to sell $1.35 billion CAD at $0.748 CAD against the U.S. dollar.
Financial Instruments
We invest in financial instruments with maturities based on our cash forecasts for the various accounts and
currency pools we manage. The types of financial instruments in which we currently invest include:
• Time deposits: Interest bearing deposits placed with financial institutions.
• Demand deposits: Interest bearing deposits placed with financial institutions. Deposited funds can be
withdrawn without notice.
• Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or
government agency purchased at a discount to mature at par.
• U.S. government or government agency obligations: Securities issued by the U.S. government or U.S.
government agencies.
• Corporate bonds: Unsecured debt securities issued by corporations.
• Asset-backed securities: Collateralized debt securities.
The following investments are carried on our consolidated balance sheet at cost, plus accrued interest:
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
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
2019
2018
2019
2018
$
759
1,483
2,030
-
876
-
3,509
-
-
1,395
465
413
229
1,069
394
5,079
$
1,301
5,915
-
2,929
-
-
-
248
-
248
111
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
$
$
1
-
8
-
-
-
9
59
-
30
10
-
-
99
-
99
-
-
15
19
133
The following table summarizes the amortized cost basis and fair value of investments in debt securities
classified as available for sale at December 31, 2019:
Major Security Type
Corporate bonds
Commercial paper
U.S. government obligations
Asset-backed securities
Millions of Dollars
Amortized Cost
Basis
Fair Value
$
$
159
38
25
19
241
159
38
25
19
241
Gross unrealized gains and gross unrealized losses included in other comprehensive income related to
investments in debt securities classified as available for sale as of December 31, 2019, were negligible.
There were no other-than-temporary impairments recognized in earnings or in other comprehensive income
during the year ended December 31, 2019.
Gross realized gains and gross realized losses included in earnings from sales and redemptions of investments
in debt securities classified as available for sale during the year ended December 31, 2019, were negligible.
The cost of securities sold and redeemed is determined using the specific identification method.
112
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents,
short-term investments, long-term investments in debt securities, OTC derivative contracts and trade
receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper,
government money market funds, government debt securities, time deposits with major international banks and
financial institutions, and high-quality corporate bonds. Our long-term investments in debt securities are
placed in high-quality corporate bonds, U.S. government obligations, and asset-backed securities.
The credit risk from our OTC derivative contracts, such as forwards, swaps and options, derives from the
counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit
limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant
nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because
these trades are cleared primarily with an exchange clearinghouse and subject to mandatory margin
requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables
arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from our petroleum operations and reflect a broad national and
international customer base, which limits our exposure to concentrations of credit risk. The majority of these
receivables have payment terms of 30 days or less, and we continually monitor this exposure and the
creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss;
however, we will sometimes use letters of credit, prepayments and master netting arrangements to mitigate
credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed
by us or owed to others to be offset against amounts due to us.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative
exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts
with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts
typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert
to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also
permit us to post letters of credit as collateral, such as transactions administered through the New York
Mercantile Exchange.
The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were
in a liability position on December 31, 2019 and December 31, 2018, was $79 million and $62 million,
respectively. For these instruments, no collateral was posted as of December 31, 2019 or December 31, 2018.
If our credit rating had been downgraded below investment grade on December 31, 2019, we would be
required to post $76 million of additional collateral, either with cash or letters of credit.
Note 15—Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit
price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed
according to the quality of valuation inputs under the following hierarchy:
• Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
• Level 2: Inputs other than quoted prices that are directly or indirectly observable.
• Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those
that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from
unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes
available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if
corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were
no material transfers in or out of Level 1 during 2019 or 2018.
113
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):
December 31, 2019
Level 1 Level 2 Level 3 Total
December 31, 2018
Level 1 Level 2 Level 3 Total
Millions of Dollars
Assets
Investment in Cenovus Energy $ 2,111
25
Investments in debt securities
172
Commodity derivatives
$ 2,308
Total assets
-
216
114
330
Liabilities
Commodity derivatives
Total liabilities
$
$
174
174
115
115
-
-
36
36
22
22
2,111
241
322
2,674
1,462
-
-
1,462
236
1,698
181
181
33
33
450
1,912
311
311
225
225
145
145
30
30
400
400
114
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
Subject to
Amounts
Net
Gross
Gross Amounts Amounts
Recognized Right of Setoff Amounts
Net
Offset Presented Collateral Amounts
Cash
December 31, 2019
Assets
Liabilities
December 31, 2018
Assets
Liabilities
$
$
322
311
450
400
3
4
9
4
319
307
441
396
193
193
280
280
126
114
161
116
4
12
-
10
122
102
161
106
At December 31, 2019 and December 31, 2018, we did not present any amounts gross on our consolidated
balance sheet where we had the right of setoff.
Non-Recurring Fair Value Measurement
The following table summarizes the fair value hierarchy by major category and date of remeasurement for
assets accounted for at fair value on a non-recurring basis:
Millions of Dollars
Year ended December 31, 2019
Net PP&E (held for sale)
November 30, 2019
December 31, 2019
Equity Method Investments
March 31, 2019
May 31, 2019
Year ended December 31, 2018
Net PP&E (held for sale)
March 31, 2018
September 30, 2018
Fair Value
$
$
194
166
171
30
250
201
Fair Value Measurements Using
Level 1
Inputs
Level 2
Inputs
Level 3
Inputs
Before-Tax
Loss
194
166
171
-
-
201
-
-
-
30
-
-
-
-
-
-
250
-
351
28
60
95
44
43
Net PP&E (held for sale)
Net PP&E held for sale was written down to fair value, less costs to sell. The fair value of each asset was
determined by its negotiated selling price (Level 1) or information gathered during marketing efforts (Level 3).
For additional information see Note 5—Asset Acquisitions and Dispositions.
Equity Method Investments
During 2019, certain equity method investments were determined to have fair values below their carrying
amounts, and the impairments were considered to be other than temporary under the guidance of FASB ASC
Topic 323. During 2019, investments using Level 1 inputs were written down to fair value, less costs to sell,
115
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):
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
Millions of Dollars
Carrying Amount
Fair Value
2019
2018
2019
2018
$
2,111
125
241
339
14,175
106
1,462
170
-
468
2,111
125
241
339
14,191
110
18,108
106
1,462
170
-
468
16,147
110
Commodity Derivatives
At December 31, 2019, commodity derivative assets and liabilities are presented net with $4 million in
obligations to return cash collateral and $12 million of rights to reclaim cash collateral, respectively. At
December 31, 2018, commodity derivative assets and liabilities are presented net with no obligations to return
cash collateral and $10 million of rights to reclaim cash collateral, respectively.
116
Note 16—Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:
Issued
Beginning of year
Distributed under benefit plans
End of year
Held in Treasury
Beginning of year
Repurchase of common stock
End of year
Shares
2019
2018
2017
1,791,637,434
4,014,769
1,795,652,203
1,785,419,175
6,218,259
1,791,637,434
1,782,079,107
3,340,068
1,785,419,175
653,288,213
57,495,601
710,783,814
608,312,034
44,976,179
653,288,213
544,809,771
63,502,263
608,312,034
Preferred Stock
We have authorized 500 million shares of preferred stock, par value $0.01 per share, none of which was issued
or outstanding at December 31, 2019 or 2018.
Noncontrolling Interests
At December 31, 2019 and 2018, we had $69 million and $125 million outstanding, respectively, of equity in
less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. For both periods,
the amounts were related to the Darwin LNG and Bayu-Darwin Pipeline operating joint ventures we control.
Repurchase of Common Stock
As of December 31, 2019, we had announced a total authorization to repurchase $15 billion of our common
stock. Repurchase of shares began in November 2016, and totaled 168,553,141 shares at a cost of $9,625
million, through December 31, 2019. In February 2020, we announced that the Board of Directors approved
an increase to our repurchase authorization from $15 billion to $25 billion, to support our plan for future share
repurchases.
Note 17—Non-Mineral Leases
The company primarily leases office buildings and drilling equipment, as well as ocean transport vessels,
tugboats, corporate aircraft, and other facilities and equipment. Certain leases include escalation clauses for
adjusting rental payments to reflect changes in price indices and other leases include payment provisions that
vary based on the nature of usage of the leased asset. Additionally, the company has executed certain leases
that provide it with the option to extend or renew the term of the lease, terminate the lease prior to the end of
the lease term, or purchase the leased asset as of the end of the lease term. In other cases, the company has
executed lease agreements that require it to guarantee the residual value of certain leased office buildings. For
additional information about guarantees, see Note 12—Guarantees. There are no significant restrictions
imposed on us by the lease agreements with regard to dividends, asset dispositions or borrowing ability.
117
Certain arrangements may contain both lease and non-lease components and we determine if an arrangement is
or contains a lease at contract inception. Only the lease components of these contractual arrangements are
subject to the provisions of ASC Topic 842, and any non-lease components are subject to other applicable
accounting guidance; however, we have elected to adopt the optional practical expedient not to separate lease
components apart from non-lease components for accounting purposes. This policy election has been adopted
for each of the company’s leased asset classes existing as of the effective date and subject to the transition
provisions of ASC Topic 842 and will be applied to all new or modified leases executed on or after January 1,
2019. For contractual arrangements executed in subsequent periods involving a new leased asset class, the
company will determine at contract inception whether it will apply the optional practical expedient to the new
leased asset class.
Leases are evaluated for classification as operating or finance leases at the commencement date of the lease
and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on
the present value of future lease payments relating to the use of the underlying asset during the lease term.
Future lease payments include variable lease payments that depend upon an index or rate using the index or
rate at the commencement date and probable amounts owed under residual value guarantees. The amount of
future lease payments may be increased to include additional payments related to lease extension, termination,
and/or purchase options when the company has determined, at or subsequent to lease commencement,
generally due to limited asset availability or operating commitments, it is reasonably certain of exercising such
options. We use our incremental borrowing rate as the discount rate in determining the present value of future
lease payments, unless the interest rate implicit in the lease arrangement is readily determinable. Lease
payments that vary subsequent to the commencement date based on future usage levels, the nature of leased
asset activities, or certain other contingencies are not included in the measurement of lease right-of-use assets
and corresponding liabilities. We have elected not to record assets and liabilities on our consolidated balance
sheet for lease arrangements with terms of 12 months or less.
We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil
and gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us
as operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we
recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated
balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income
statement and statement of cash flows, such costs are offset by the reimbursement we receive from our
coventurers for their share of the lease cost as the underlying leased asset is utilized in joint venture activities.
As a result, lease cost is presented in our consolidated income statement and statement of cash flows on a
proportional basis. If we are a nonoperating coventurer, we recognize a right-of-use asset and corresponding
lease liability only if we were a specified contractual party to the lease arrangement and the arrangement could
be legally enforced against us. In this circumstance, we would recognize both the right-of-use asset and
corresponding lease liability on our consolidated balance sheet on a proportional basis consistent with our
undivided interest ownership in the related joint venture.
The company has historically recorded certain finance leases executed by investee companies accounted for
under the proportionate consolidation method of accounting on its consolidated balance sheet on a proportional
basis consistent with its ownership interest in the investee company. In addition, the company has historically
recorded finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional
basis pursuant to accounting guidance applicable prior to January 1, 2019. As of December 31, 2018, $420
million of finance lease assets (net of accumulated DD&A) and $688 million of finance lease liabilities were
recorded on our consolidated balance sheet associated with these leases. In accordance with the transition
provisions of ASC Topic 842, and since we have elected to adopt the package of optional transition-related
practical expedients, the historical accounting treatment for these leases has been carried forward and is subject
to reconsideration upon the modification or other required reassessment of the arrangements prior to lease term
expiration.
In connection with our adoption of ASC Topic 842, we have recorded on our consolidated balance sheet $57
million of operating leases executed by investee companies accounted for under the proportionate
118
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:
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
Net properties, plants and equipment as of December 31, 2018
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
$
$
1,044
(550)
494
Adoption of ASC Topic 842 as of January 1, 2019
$
998
Lease Liabilities
Short-term debt
Long-term debt
Total finance leases debt as of December 31, 2018
$
$
79
698
777
Adoption of ASC Topic 842 as of January 1, 2019
$
998
Amounts recognized in line items in our Consolidated
Balance Sheet at December 31, 2019
Right-of-Use Assets
Properties, plants and equipment
Gross
Accumulated depreciation, depletion and amortization
$
1,039
(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 $335 million.
40
896
390
$
$
119
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
*Short-term debt and long-term debt include proportionately consolidated finance lease liabilities of $56 million and $579 million, respectively.
585
932 $
347
720
633
87
$
$
$
The following table summarizes our lease costs for 2019:
Lease Cost*
Operating lease cost
Finance lease cost
Amortization of right-of-use assets
Interest on lease liabilities
Millions of Dollars
2019
$
341
99
37
77
554
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 short-term lease commitments amount to $31 million, of
which $18 million is related to leases whose terms have not yet commenced as of December 31, 2019.
***Variable lease cost and sublease income are immaterial for the period presented and therefore are not included in the table above.
$
120
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
5.19
8.70
3.10
5.53
The following table summarizes other lease information for 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
Millions of Dollars
2019
$
203
27
81
499
Right-of-use assets obtained in exchange for operating lease liabilities
Right-of-use assets obtained in exchange for finance lease liabilities
26
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers. In
addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its intended
use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.
$
The following table summarizes future lease payments for operating and finance leases at December 31, 2019:
Millions of Dollars
Operating
Leases
Finance
Leases
$
Maturity of Lease Liabilities
2020
2021
2022
2023
2024
Remaining years
Total*
Less: portion representing imputed interest
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.
348
247
130
82
63
149
1,019
(87)
932
120
104
102
88
84
382
880
(160)
720
$
121
At December 31, 2018, future minimum payments due under finance (capital) leases pursuant to
ASC Topic 840 were:
2019
2020
2021
2022
2023
Remaining years
Total
Less: portion representing imputed interest
Capital lease obligations
Millions
of Dollars
118
116
100
98
87
453
972
(195)
777
$
$
At December 31, 2018, future undiscounted minimum rental payments due under noncancelable operating
leases pursuant to ASC Topic 840 were:
2019
2020
2021
2022
2023
Remaining years
Total
Less: income from subleases
Net minimum operating lease payments
Millions
of Dollars
248
425
136
319
54
212
1,394
(7)
1,387
$
$
For the years ended December 31, operating lease rental expense pursuant to ASC Topic 840 was:
Total rentals
Less: sublease rentals
Millions of Dollars
2018
253
(16)
237
2017
264
(20)
244
$
$
122
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:
Change in Benefit Obligation
Benefit obligation at January 1
Service cost
Interest cost
Plan participant contributions
Plan amendments
Actuarial (gain) loss
Benefits paid
Curtailment
Settlement
Recognition of termination benefits
Foreign currency exchange rate change
Benefit obligation at December 31*
*Accumulated benefit obligation portion of above at
December 31:
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
Actual return on plan assets
Company contributions
Plan participant contributions
Benefits paid
Settlement
Foreign currency exchange rate change
Fair value of plan assets at December 31
Funded Status
Millions of Dollars
Pension Benefits
2019
U.S.
2018
Int’l.
U.S.
Int’l.
Other Benefits
2019
2018
$
$
$
$
$
$
2,136
79
79
-
-
278
(253)
-
-
-
-
2,319
3,438
69
97
2
-
387
(147)
(69)
-
1
102
3,880
3,236
83
99
-
-
(44)
(507)
(4)
(730)
3
-
2,136
3,845
81
107
2
7
(259)
(143)
(3)
-
-
(199)
3,438
2,161
3,594
1,969
3,066
1,336
273
235
-
(253)
-
-
1,591
(728)
3,358
529
464
2
(147)
-
100
4,306
426
2,541
(112)
144
-
(507)
(730)
-
1,336
(800)
3,647
(106)
156
2
(143)
-
(198)
3,358
(80)
218
1
8
20
-
27
(59)
-
-
-
1
216
-
-
39
20
(59)
-
-
-
(216)
265
1
8
22
-
(10)
(67)
-
-
-
(1)
218
-
-
45
22
(67)
-
-
-
(218)
123
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Noncurrent assets
Current liabilities
Noncurrent liabilities
Total recognized
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
Millions of Dollars
Pension Benefits
2019
2018
Other Benefits
2019
2018
U.S.
Int’l.
U.S.
Int’l.
$
$
-
(21)
(707)
(728)
765
(6)
(333)
426
-
(59)
(741)
(800)
232
(4)
(308)
(80)
-
(42)
(174)
(216)
-
(44)
(174)
(218)
3.25 %
4.00
2.35
3.35
4.25
4.00
3.05
3.65
3.10
4.05
-
3.95 %
5.80
4.00
2.90
4.10
3.65
3.80
5.80
4.00
2.90
4.30
3.75
4.05
3.30
-
-
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
2019
2018
Other Benefits
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
Unrecognized prior service cost (credit)
$
479
-
227
(2)
516
-
310
(4)
8
(183)
(21)
(216)
124
Millions of Dollars
Pension Benefits
2018
Other Benefits
2019
2018
Int’l.
U.S.
Int’l.
2019
U.S.
Sources of Change in Other
Comprehensive Income (Loss)
Net gain (loss) arising during the period
Amortization of actuarial (gain) loss included
in income (loss)*
Net change during the period
Prior service credit (cost) arising during the
period
Amortization of prior service cost (credit)
included in income (loss)
Net change during the period
*Includes settlement losses recognized in 2019 and 2018.
$
(79)
51
(177)
116
37
-
-
-
$
$
$
32
83
-
(2)
(2)
249
72
-
-
-
17
31
48
(7)
(5)
(12)
(27)
(2)
(29)
10
(1)
9
-
-
(33)
(33)
(35)
(35)
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
Benefits
U.S.
Int’l.
Other
Benefits
Unrecognized net actuarial (gain) loss
Unrecognized prior service credit
$
50
-
23
(2)
1
(31)
For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected
benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $2,073 million,
$1,919 million, and $1,635 million, respectively, at December 31, 2019, and $1,871 million, $1,737 million,
and $1,373 million, respectively, at December 31, 2018.
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and
the accumulated benefit obligation were $601 million and $542 million, respectively, at December 31, 2019,
and were $586 million and $504 million, respectively, at December 31, 2018.
125
The components of net periodic benefit cost of all defined benefit plans are presented in the following table:
Millions of Dollars
2019
Pension Benefits
2018
Other Benefits
2017
2019
2018
2017
U.S. Int’l. U.S.
Int’l. U.S.
Int’l.
$
79
79
69
97
83
99
81
107
89
118
77
103
(74)
(138)
(114)
(155)
(132) (158)
1
8
-
1
8
-
2
9
-
-
(2)
-
(5)
4
(6)
(33)
(35)
(36)
54
62
200
$
32
-
58
53
196
317
31
-
59
69
131
279
50
-
66
(2)
-
(26)
(1)
-
(27)
(3)
-
(28)
Components of Net
Periodic Benefit Cost
Service cost
Interest cost
Expected return on plan
assets
Amortization of prior
service cost (credit)
Recognized net actuarial
loss (gain)
Settlements
Net periodic benefit cost
The components of net periodic benefit cost, other than the service cost component, are included in the “Other
expenses” line item on our consolidated income statement.
In 2018, we purchased a group annuity contract from Prudential and transferred $730 million of future benefit
obligations from the U.S. qualified pension plan to Prudential. The purchase of the group annuity contract was
funded directly by plan assets of the U.S. qualified pension plan. Effective January 1, 2019, the Cash Balance
Account (Title II) of the ConocoPhillips Retirement Plan, a U.S. qualified pension plan, was closed to new
entrants. New employees and rehires on or after January 1, 2019, and employees that elected to opt out of
Title II will no longer receive pay credits to their Cash Balance Account and instead will be eligible for a
Company Retirement Contribution (CRC) as described in the Defined Contribution Plans section.
We recognized pension settlement losses of $62 million in 2019, $196 million in 2018, and $131 million in
2017 as lump-sum benefit payments from certain U.S. pension plans exceeded the sum of service and interest
costs for those plans and led to recognition of settlement losses.
The sale of two ConocoPhillips U.K. subsidiaries completed during the third quarter of 2019 led to a
significant reduction of future services of active employees in certain international pension plans, resulting in a
curtailment. In conjunction with the recognition of the curtailment, the fair market values of pension plan
assets were updated, the pension benefit obligation was remeasured, and the net pension asset decreased by
$43 million, resulting in a corresponding decrease to other comprehensive income. This is primarily a result of
a decrease in the discount rate from 2.90 percent at December 31, 2018 to 1.80 percent at September 30, 2019
offset by a decrease in the pension benefit obligation from curtailment.
In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-
line basis over the average remaining service period of employees expected to receive benefits under the plan.
For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.
We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans
are contributory and subject to various cost sharing features, with participant and company contributions
adjusted annually; the life insurance plans are noncontributory. The measurement of the U.S. pre-65 retiree
medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 7 percent in
2020 that declines to 5 percent by 2028. The measurement of the U.S. post-65 retiree medical accumulated
postretirement benefit obligation assumes an ultimate health care cost trend rate of 4 percent achieved in 2020
126
that increases to 5 percent by 2028. A one-percentage-point change in the assumed health care cost trend rate
would be immaterial to ConocoPhillips.
Plan Assets—We follow a policy of broadly diversifying pension plan assets across asset classes and
individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes
that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed
income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to
the investment program from time to time. The target allocations for plan assets are 37 percent equity
securities, 56 percent debt securities, 6 percent real estate and 1 percent other. Generally, the plan investments
are publicly traded, therefore minimizing liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets. There have
been no changes in the methodologies used at December 31, 2019 and 2018.
• Fair values of equity securities and government debt securities categorized in Level 1 are primarily
based on quoted market prices in active markets for identical assets and liabilities.
• Fair values of corporate debt securities, agency and mortgage-backed securities and government debt
securities categorized in Level 2 are estimated using recently executed transactions and quoted market
prices for similar assets and liabilities in active markets and for identical assets and liabilities in
markets that are not active. If there have been no market transactions in a particular fixed income
security, its fair value is calculated by pricing models that benchmark the security against other
securities with actual market prices. When observable quoted market prices are not available, fair
value is based on pricing models that use something other than actual market prices (e.g., observable
inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these
securities are categorized in Level 3 of the fair value hierarchy.
• Fair values of investments in common/collective trusts are determined by the issuer of each fund
based on the fair value of the underlying assets.
• Fair values of mutual funds are based on quoted market prices, which represent the net asset value of
shares held.
• Time deposits are valued at cost, which approximates fair value.
• Cash is valued at cost, which approximates fair value. Fair values of international cash equivalents
categorized in Level 2 are valued using observable yield curves, discounting and interest rates. U.S.
cash balances held in the form of short-term fund units that are redeemable at the measurement date
are categorized as Level 2.
• Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices.
For other derivatives classified in Level 2, the values are generally calculated from pricing models
with market input parameters from third-party sources.
• Fair values of insurance contracts are valued at the present value of the future benefit payments owed
by the insurance company to the plans’ participants.
• Fair values of real estate investments are valued using real estate valuation techniques and other
methods that include reference to third-party sources and sales comparables where available.
127
• A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity
contract, which is calculated as the market value of investments held under this contract, less the
accumulated benefit obligation covered by the contract. The participating interest is classified as
Level 3 in the fair value hierarchy as the fair value is determined via a combination of quoted market
prices, recently executed transactions, and an actuarial present value computation for contract
obligations. At December 31, 2019, the participating interest in the annuity contract was valued at
$95 million and consisted of $235 million in debt securities, less $140 million for the accumulated
benefit obligation covered by the contract. At December 31, 2018, the participating interest in the
annuity contract was valued at $84 million and consisted of $228 million in debt securities, less $144
million for the accumulated benefit obligation covered by the contract. The net change from 2018 to
2019 is due to an increase in the fair value of the underlying investments of $7 million offset by a
decrease in the present value of the contract obligation of $4 million. The participating interest is not
available for meeting general pension benefit obligations in the near term. No future company
contributions are required and no new benefits are being accrued under this insurance annuity
contract.
The fair values of our pension plan assets at December 31, by asset class were as follows:
Millions of Dollars
U.S.
International
Level 1 Level 2 Level 3
Total Level 1 Level 2 Level 3
Total
$
2019
Equity securities
U.S.
International
Mutual funds
Debt securities
Government
Corporate
Mutual funds
Cash and cash equivalents
Derivatives
Real estate
Total in fair value hierarchy
$
94
98
93
-
-
-
-
-
-
285
-
-
-
-
2
-
-
-
-
2
7
-
-
-
-
-
-
-
-
7
101
98
93
-
2
-
-
-
-
294
435
266
245
1,412
-
392
98
11
-
2,859
-
-
267
-
-
-
-
-
-
267
-
-
-
435
266
512
-
-
-
-
-
132
132
1,412
-
392
98
11
132
3,258
-
-
$
Investments measured at net asset value*
Equity securities
Common/collective trusts
Debt securities
Common/collective trusts
Cash and cash equivalents
Real estate
Total**
*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value
using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value
amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in
Fair Value of Plan Assets.
**Excludes the participating interest in the insurance annuity contract with a net asset of $95 million and net receivables related to security
transactions of $9 million.
-
-
-
2,859
760
-
112
4,297
637
25
83
1,496
-
-
-
132
-
-
-
285
-
-
-
267
-
-
-
7
-
-
-
2
167
457
$
-
-
-
-
128
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
Real estate
Total in fair value hierarchy
$
74
80
76
-
-
-
-
-
-
-
230
-
-
-
-
2
-
-
-
-
-
2
20
-
-
-
-
-
-
-
-
-
20
94
80
76
-
2
-
-
-
-
-
252
371
241
213
889
-
363
71
6
(17)
-
2,137
-
-
181
-
-
-
-
-
-
-
181
-
-
-
371
241
394
-
-
-
-
-
-
124
124
889
-
363
71
6
(17)
124
2,442
-
-
$
Investments measured at net asset value*
Equity securities
Common/collective trusts
Debt securities
Common/collective trusts
Cash and cash equivalents
Real estate
Total**
*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value
using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value
amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in
Fair Value of Plan Assets.
**Excludes the participating interest in the insurance annuity contract with a net asset of $84 million and net receivables related to security
transactions of $16 million.
-
-
-
2,137
641
-
109
3,345
548
5
80
1,249
-
-
-
181
-
-
-
230
-
-
-
124
-
-
-
20
-
-
-
2
153
364
$
-
-
-
-
Level 3 activity was not material for all periods.
Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement
Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign
plans are dependent upon local laws and tax regulations. In 2020, we expect to contribute approximately $350
million to our domestic qualified and nonqualified pension and postretirement benefit plans and $90 million to
our international qualified and nonqualified pension and postretirement benefit plans.
129
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
Benefits
U.S.
Int’l.
Other
Benefits
2020
2021
2022
2023
2024
2025–2029
$
447
270
250
217
220
822
150
156
158
163
170
927
32
29
27
24
22
64
Severance Accrual
The following table summarizes our severance accrual activity for the year ended December 31, 2019:
Balance at December 31, 2018
Accruals
Benefit payments
Balance at December 31, 2019
Millions of Dollars
$
$
48
(1)
(24)
23
Of the remaining balance at December 31, 2019, $5 million is classified as short-term.
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can
deposit up to 75 percent of their eligible pay, subject to statutory limits, in the CPSP to a choice of
approximately 17 investment options. Employees who participate in the CPSP and contribute 1 percent of
their eligible pay receive a 6 percent company cash match with a potential company discretionary cash
contribution of up to 6 percent. Effective January 1, 2019, new employees, rehires, and employees that elected
to opt out of Title II are eligible to receive a CRC of 6 percent of eligible pay into their CPSP. After three
years of service with the company, the employee is 100 percent vested in any CRC. Company contributions
charged to expense for the CPSP and predecessor plans were $82 million in 2019, $82 million in 2018, and
$77 million in 2017.
We have several defined contribution plans for our international employees, each with its own terms and
eligibility depending on location. Total compensation expense recognized for these international plans was
approximately $30 million in 2019, $31 million in 2018, and $35 million in 2017.
Share-Based Compensation Plans
The 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by
shareholders in May 2014. Over its 10-year life, the Plan allows the issuance of up to 79 million shares of our
common stock for compensation to our employees and directors; however, as of the effective date of the Plan,
(i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common
stock represented by awards granted under the prior plans that are forfeited, expire or are cancelled without
delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the
company shall be available for awards under the Plan, and no new awards shall be granted under the prior
plans. Of the 79 million shares available for issuance under the Plan, no more than 40 million shares of
common stock are available for incentive stock options. The Human Resources and Compensation Committee
130
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:
Compensation cost
Tax benefit
Millions of Dollars
2019
274
71
$
2018
265
64
2017
227
76
Stock Options—Stock options granted under the provisions of the Plan and prior plans permit purchase of our
common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock
on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-
third of the options awarded vesting and becoming exercisable on each anniversary date following the date of
grant. Options awarded to certain employees already eligible for retirement vest within six months of the grant
date, but those options do not become exercisable until the end of the normal vesting period. Beginning in
2018, stock option grants were discontinued and replaced with three-year, time-vested restricted stock units
which generally will be cash-settled.
The fair market values of the options granted in 2017 were measured on the date of grant using the
Black-Scholes-Merton option-pricing model. The weighted-average assumptions used were as follows:
Assumptions used
Risk-free interest rate
Dividend yield
Volatility factor
Expected life (years)
2017
2.24 %
4.00 %
28.12 %
6.39
There were no ranges in the assumptions used to determine the fair market values of our options granted in
2017.
We believe our historical volatility for periods prior to the 2012 separation of our Downstream businesses is no
longer relevant in estimating expected volatility. For 2017, expected volatility was based on the weighted-
average blend of the company’s historical stock price volatility from May 1, 2012 (the date of separation of our
131
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:
Outstanding at December 31, 2018
Exercised
Forfeited
Expired or cancelled
Outstanding at December 31, 2019
Vested at December 31, 2019
Exercisable at December 31, 2019
Options
19,379,677
(1,339,480)
-
-
18,040,197
17,922,026
17,172,815
Weighted-Average
Exercise Price
Millions of Dollars
Aggregate
Intrinsic Value
$
$
$
$
52.88
36.28
54.11
54.14
54.33
$
$
$
$
214
39
206
205
194
The weighted-average remaining contractual term of outstanding options, vested options and exercisable
options at December 31, 2019, was 4.43 years, 4.41 years and 4.29 years, respectively. The weighted-average
grant date fair value of stock option awards granted during 2017 was $9.18. The aggregate intrinsic value of
options exercised was $94 million in 2018 and $4 million in 2017.
During 2019, we received $49 million in cash and realized a tax benefit of $13 million from the exercise of
options. At December 31, 2019, the remaining unrecognized compensation expense from unvested options
was zero.
Stock Unit Program—Generally, restricted stock units are granted annually under the provisions of the Plan
and vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock
units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual
installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc
to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest
vary by award.
Stock-Settled
Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per
unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not issued as common stock until the earlier of separation from the company or the end of the regularly
scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a quarterly
cash payment of a dividend equivalent that is charged to retained earnings. The grant date fair market value of
these restricted stock units is deemed equal to the average ConocoPhillips stock price on the grant date. The
grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal
to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will
not be received.
132
The following summarizes our stock-settled stock unit activity for the year ended December 31, 2019:
Outstanding at December 31, 2018
Granted
Forfeited
Issued
Outstanding at December 31, 2019
Not Vested at December 31, 2019
Stock Units
7,546,973
2,045,503
(99,748)
(3,269,682)
6,223,046
4,185,141
Weighted-Average Millions of Dollars
Total Fair Value
Grant Date Fair Value
$
$
43.41
67.77
62.93
34.32
55.99
56.17
$
225
At December 31, 2019, the remaining unrecognized compensation cost from the unvested stock-settled units
was $93 million, which will be recognized over a weighted-average period of 1.71 years, the longest period
being 2.73 years. The weighted-average grant date fair value of stock unit awards granted during 2018 and
2017 was $52.45 and $48.77, respectively. The total fair value of stock units issued during 2018 and 2017 was
$154 million and $159 million, respectively.
Cash-Settled
Beginning in 2018, cash-settled executive restricted stock units replaced the stock option program. These
restricted stock units, subject to elections to defer, will be settled in cash equal to the fair market value of a
share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the
balance sheet. Units awarded to retirement eligible employees vest six months from the grant date; however,
those units are not settled until the earlier of separation from the company or the end of the regularly scheduled
vesting period. Compensation expense is initially measured using the average fair market value of
ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock
price through the end of each subsequent reporting period, through the settlement date. Recipients receive an
accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested
dividend is paid at the time of settlement, subject to the terms and conditions of the award.
The following summarizes our cash-settled stock unit activity for the year ended December 31, 2019:
Stock Units
Weighted-Average Millions of Dollars
Total Fair Value
Grant Date Fair Value
Outstanding at December 31, 2018
Granted
Forfeited
Issued
Outstanding at December 31, 2019
Not Vested at December 31, 2019
376,608
319,552
(6,914)
(92,255)
596,991
153,457
$
$
62.21
68.20
61.35
61.61
64.54
64.54
$
6
At December 31, 2019, the remaining unrecognized compensation cost from the unvested cash-settled units
was $5 million, which will be recognized over a weighted-average period of 1.70 years, the longest period
being 2.12 years. The weighted-average grant date fair value of stock unit awards granted during 2018 was
$53.68. The total fair value of stock units issued during 2018 was $1 million.
133
Performance Share Program—Under the Plan, we also annually grant restricted performance share units
(PSUs) to senior management. These PSUs are authorized three years prior to their effective grant date (the
performance period). Compensation expense is initially measured using the average fair market value of
ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock
price through the end of each subsequent reporting period, through the grant date for stock-settled awards and
the settlement date for cash-settled awards.
Stock-Settled
For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for
retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee
separates from the company. With respect to awards for performance periods beginning in 2009 through 2012,
PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55
with five years of service or five years after the grant date of the award, and restrictions do not lapse until the
earlier of the employee’s separation from the company or five years after the grant date (although recipients
can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these
awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Since these awards
are authorized three years prior to the grant date, for employees eligible for retirement by or shortly after the
grant date, we recognize compensation expense over the period beginning on the date of authorization and
ending on the date of grant. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a
dividend equivalent that is charged to retained earnings. Beginning in 2013, PSUs authorized for future grants
will vest, absent employee election to defer, upon settlement following the conclusion of the three-year
performance period. We recognize compensation expense over the period beginning on the date of
authorization and ending on the conclusion of the performance period. PSUs are settled by issuing one share
of ConocoPhillips common stock per unit.
The following summarizes our stock-settled Performance Share Program activity for the year ended
December 31, 2019:
Outstanding at December 31, 2018
Granted
Forfeited
Issued
Outstanding at December 31, 2019
Not Vested at December 31, 2019
Stock Units
2,335,542
77,841
-
(388,559)
2,024,824
15,616
Weighted-Average
Grant Date Fair Value
Millions of Dollars
Total Fair Value
$
$
$
50.45
68.90
53.66
50.55
47.80
$
25
At December 31, 2019, the remaining unrecognized compensation cost from unvested stock-settled
performance share awards was zero. The weighted-average grant date fair value of stock-settled PSUs granted
during 2018 and 2017 was $53.28 and $49.76, respectively. The total fair value of stock-settled PSUs issued
during 2018 and 2017 was $29 million and $57 million, respectively.
Cash-Settled
In connection with and immediately following the separation of our Downstream businesses in 2012, grants of
new PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent
employee election to defer, on the earlier of five years after the grant date of the award or the date the
employee becomes eligible for retirement. For employees eligible for retirement by or shortly after the grant
date, we recognize compensation expense over the period beginning on the date of authorization and ending on
the date of grant. Otherwise, we recognize compensation expense beginning on the grant date and ending on
the date the PSUs are scheduled to vest. These PSUs are settled in cash equal to the fair market value of a
share of ConocoPhillips common stock per unit on the settlement date and thus are classified as liabilities on
the balance sheet. Until settlement occurs, recipients of the PSUs receive a quarterly cash payment of a
134
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:
Outstanding at December 31, 2018
Granted
Forfeited
Settled
Outstanding at December 31, 2019
Not Vested at December 31, 2019
Stock Units
1,131,007
1,958,043
-
(2,479,776)
609,274
38,487
Weighted-Average
Grant Date Fair Value
Millions of Dollars
Total Fair Value
$
$
$
62.21
68.90
69.10
64.54
64.54
$
171
At December 31, 2019, the remaining unrecognized compensation cost from unvested cash-settled
performance share awards was zero. The weighted-average grant date fair value of cash-settled PSUs granted
during 2018 and 2017 was $53.28 and $49.76, respectively. The total fair value of cash-settled performance
share awards settled during 2018 and 2017 was $22 million and $24 million, respectively.
From inception of the Performance Share Program through 2013, approved PSU awards were granted after the
conclusion of performance periods. Beginning in February 2014, initial target PSU awards are issued near the
beginning of new performance periods. These initial target PSU awards will terminate at the end of the
performance periods and will be settled after the performance periods have ended. Also in 2014, initial target
PSU awards were issued for open performance periods that began in prior years. For the open performance
period beginning in 2012, the initial target PSU awards terminated at the end of the three-year performance
period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the
initial target PSU awards terminated at the end of the three-year performance period and were settled after the
performance period ended. There is no effect on recognition of compensation expense.
Other—In addition to the above active programs, we have outstanding shares of restricted stock and restricted
stock units that were either issued as part of our non-employee director compensation program for current and
former members of the company’s Board of Directors or as part of an executive compensation program that
has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or
dividend equivalent.
135
The following summarizes the aggregate activity of these restricted shares and units for the year ended
December 31, 2019:
Outstanding at December 31, 2018
Granted
Cancelled
Issued
Outstanding at December 31, 2019
Stock Units
1,107,315
64,063
(2,307)
(177,163)
991,908
Weighted-Average
Grant Date Fair Value
Millions of Dollars
Total Fair Value
$
$
46.57
63.58
23.73
49.23
47.24
$
11
At December 31, 2019, all outstanding restricted stock and restricted stock units were fully vested and there
was no remaining compensation cost to be recorded. The weighted-average grant date fair value of awards
granted during 2018 and 2017 was $62.01 and $48.87, respectively. The total fair value of awards issued
during 2018 and 2017 was $17 million and $4 million, respectively.
Note 19—Income Taxes
Income taxes charged to net income (loss) were:
Income Taxes
Federal
Current
Deferred
Foreign
Current
Deferred
State and local
Current
Deferred
Millions of Dollars
2019
2018
18
(113)
2,545
(323)
148
(8)
2,267
4
545
3,273
(166)
108
(96)
3,668
2017
79
(3,046)
1,729
(510)
51
(125)
(1,822)
$
$
136
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
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
Net deferred tax assets
Net deferred tax liabilities
2019
8,660
35
-
234
8,929
542
2,339
1,722
777
8,968
345
14,693
(10,214)
4,479
4,450
$
$
2018
8,004
60
61
156
8,281
641
2,891
104
330
2,378
398
6,742
(3,040)
3,702
4,579
At December 31, 2019, noncurrent assets and liabilities included deferred taxes of $184 million and
$4,634 million, respectively. At December 31, 2018, noncurrent assets and liabilities included deferred taxes
of $442 million and $5,021 million, respectively.
At December 31, 2019, the components of our loss and credit carryforwards before and after consideration of
the applicable valuation allowances were:
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
Millions of Dollars
Gross Deferred
Tax Asset
Net Deferred Expiration of
Tax Asset After Net Deferred
Tax Asset
Valuation Allowance
$
$
7,696
250
202
370
450
8,968
14
250
32
50
413
759
2028
2036-2038
2024
Various
Post 2025
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely
than not, be realized. During 2019, valuation allowances increased a total of $7,174 million. The increase
primarily relates to deferred tax assets recognized during 2019 as a result of the finalization of rules related to
the U.S. Tax Cuts and Jobs Act (Tax Legislation including ongoing issuance of tax regulations related to such
legislation), as further discussed below. Based on our historical taxable income, expectations for the future,
and available tax-planning strategies, management expects deferred tax assets, net of valuation allowance, will
primarily be realized as offsets to reversing deferred tax liabilities.
137
On December 2, 2019, the Internal Revenue Service finalized foreign tax credit regulations related to the 2017
Tax Cuts and Jobs Act. Due to the finalization of these regulations, in the fourth quarter of 2019 we
recognized $151 million of net deferred tax assets. Correspondingly, we recorded $6,642 million of existing
foreign tax credit carryovers where recognition was previously considered to be remote. Present legislation
still makes their realization unlikely and therefore these credits have been offset with a full valuation
allowance.
At December 31, 2019, unremitted income considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures totaled approximately $4,196 million. Deferred income taxes
have not been provided on this amount, as we do not plan to initiate any action that would require the payment
of income taxes. The estimated amount of additional tax, primarily local withholding tax, that would be
payable on this income if distributed is approximately $210 million.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2019,
2018 and 2017:
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
Settlements
Lapse of statute
Balance at December 31
Millions of Dollars
2019
2018
$
$
1,081
9
120
(22)
(9)
(2)
1,177
882
268
43
(73)
(35)
(4)
1,081
2017
381
612
109
(129)
(5)
(86)
882
Included in the balance of unrecognized tax benefits for 2019, 2018 and 2017 were $1,100 million,
$1,081 million and $882 million, respectively, which, if recognized, would impact our effective tax rate. The
balance of the unrecognized tax benefits increased in 2019 mainly due to the treatment of our PDVSA
settlement. The balance of the unrecognized tax benefits increased in 2018 mainly due to the treatment of
distributions from certain foreign subsidiaries. The balance of unrecognized tax benefits increased in 2017
mainly due to the recognition of a U.S. worthless securities deduction that we do not believe will generate a
cash tax benefit. See Note 13—Contingencies and Commitments, for more information on the PDVSA
settlement.
At December 31, 2019, 2018 and 2017, accrued liabilities for interest and penalties totaled $42 million,
$45 million and $54 million, respectively, net of accrued income taxes. Interest and penalties resulted in a
benefit to earnings of $3 million in 2019, a benefit to earnings of $4 million in 2018, and no impact to earnings
in 2017.
We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major
jurisdictions are generally complete as follows: U.K. (2015), Canada (2014), U.S. (2014) and Norway (2018).
Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of
completion in the many jurisdictions in which we operate around the world. Consequently, the balance in
unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible such
changes could be significant when compared with our total unrecognized tax benefits, but the amount of
change is not estimable.
138
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:
Income (loss) before income taxes
United States
$
Foreign
$
$
Federal statutory income tax
Non-U.S. effective tax rates
Tax Legislation
Canada disposition
U.K. disposition
Recovery of outside basis
Adjustment to tax reserves
Adjustment to valuation allowance
APLNG impairment
State income tax
Malaysia Deepwater Incentive
Enhanced oil recovery credit
Other
$
Millions of Dollars
2019
2018
Percent of Pre-Tax Income (Loss)
2017
2019
2018
2017
4,704
4,820
9,524
2,000
1,399
-
-
(732)
(77)
9
(225)
-
123
(164)
(27)
(39)
2,267
2,867
7,106
9,973
2,095
1,766
(10)
-
(150)
(21)
(4)
(26)
-
135
-
(99)
(18)
3,668
(5,250)
2,635
(2,615)
(915)
625
(852)
(1,277)
-
(962)
881
-
834
(84)
-
(68)
(4)
(1,822)
49.4 %
50.6
100.0 %
28.7
71.3
100.0
200.8
(100.8)
100.0
21.0 %
14.7
-
-
(7.7)
(0.8)
0.1
(2.4)
-
1.3
(1.7)
(0.3)
(0.4)
23.8 %
21.0
17.7
(0.1)
-
(1.5)
(0.2)
-
(0.3)
-
1.4
-
(1.0)
(0.2)
36.8
35.0
(23.9)
32.6
48.8
-
36.8
(33.7)
-
(31.9)
3.2
-
2.6
0.2
69.7
Our effective tax rate for 2019 was favorably impacted by the sale of two of our U.K. subsidiaries. The
disposition generated a before-tax gain of more than $1.7 billion with an associated tax benefit of $335
million. The disposition generated a U.S. capital loss of approximately $2.1 billion which has generated a U.S.
tax benefit of approximately $285 million. The remaining U.S. capital loss has been recorded as a deferred tax
asset fully offset with a valuation allowance. See Note 5—Asset Acquisitions and Dispositions, for additional
information on the disposition.
During the third quarter of 2019, we received final partner approval in Malaysia Block G to claim certain
deepwater tax credits. As a result, we recorded an income tax benefit of $164 million.
The decrease in the effective tax rate for 2018 was primarily due to the impact of the Clair Field disposition in
the U.K. and our overall income position, partially offset by our mix of income among taxing jurisdictions.
Our effective tax rate for 2018 was favorably impacted by the sale of a U.K. subsidiary to BP. The subsidiary
held 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the U.K. The disposition
generated a before-tax gain of $715 million with no associated tax cost. See Note 5—Asset Acquisitions and
Dispositions, for additional information on the disposition.
Tax Legislation was enacted in the U.S. on December 22, 2017, reducing the U.S. federal corporate income tax
rate to 21 percent from 35 percent, requiring companies to pay a one-time transition tax on earnings of certain
foreign subsidiaries that were previously tax deferred and creating new taxes on certain foreign-sourced
earnings.
139
SAB 118 measurement period
We applied the guidance in Staff Accounting Bulletin No. 118 when accounting for the enactment-date effects
of Tax Legislation in 2017 and throughout 2018. At December 31, 2017, we had not completed our
accounting for all the enactment-date income tax effects of Tax Legislation under ASC 740, Income Taxes, for
the remeasurement of deferred tax assets and liabilities and the one-time transition tax. As of December 31,
2018, we had completed our accounting for all the enactment-date income tax effects of Tax Legislation. As
further discussed below, during 2018, we recognized adjustments of $10 million to the provisional amounts
recorded at December 31, 2017, and included these adjustments as a component of income tax provision.
Provisional Amounts—Foreign tax effects
The one-time transition tax is based on our total post-1986 earnings, the tax on which we previously deferred
from U.S. income taxes under U.S. law. We estimated at December 31, 2017, that we would not incur a one-
time transition tax. Upon further analyses of Tax Legislation and Notices and regulations issued and proposed
by the U.S. Department of the Treasury and the Internal Revenue Service, we finalized our calculations of the
transition tax liability during 2018. Based upon this analysis, we did not incur a one-time transition tax.
As a result of the Tax Legislation, we removed the indefinite reinvestment assertion on one of our foreign
subsidiaries and recorded a tax expense of $56 million in the fourth quarter of 2017.
Deferred tax assets and liabilities
As of December 31, 2017, we remeasured certain deferred tax assets and liabilities based on the rates at which
they were expected to reverse in the future (which was generally 21 percent), by recording a provisional
amount of $908 million. Upon further analysis of certain aspects of Tax Legislation and refinement of our
calculations during the 12 months ended December 31, 2018, we adjusted our provisional amount by $10
million, which is included as a component of income tax expense.
Global intangible low-taxed income (GILTI)
We have elected to account for GILTI in the year the tax is incurred. For 2019 and 2018, the current-year U.S.
income tax impact related to GILTI activities is immaterial.
Our effective tax rate in 2017 was favorably impacted by a tax benefit of $1,277 million related to the Canada
disposition. This tax benefit was primarily associated with a deferred tax recovery related to the Canadian
capital gains exclusion component of the 2017 Canada disposition and the recognition of previously
unrealizable Canadian capital asset tax basis. The Canada disposition, along with the associated restructuring
of our Canadian operations, may generate an additional tax benefit of $822 million. However, since we
believe it is not likely we will receive a corresponding cash tax savings, this $822 million benefit has been
offset by a full tax reserve. See Note 5—Asset Acquisitions and Dispositions for additional information on our
Canada disposition.
The impairment of our APLNG investment in the second quarter of 2017 did not generate a tax benefit. See
the “APLNG” section of Note 6—Investments, Loans and Long-Term Receivables, for information on the
impairment of our APLNG investment.
Certain operating losses in jurisdictions outside of the U.S. only yield a tax benefit in the U.S. as a worthless
security deduction. For 2019, 2018 and 2017, before consideration of unrecorded tax benefits discussed above,
the amount of the tax benefit was $9 million, $36 million and $962 million, respectively.
140
Note 20—Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss in the equity section of the balance sheet included:
Millions of Dollars
Net
Unrealized
Loss on
Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
Defined
Benefit Plans
$
December 31, 2016
Other comprehensive income (loss)
December 31, 2017
Other comprehensive income (loss)
Cumulative effect of adopting ASU No. 2016-01*
December 31, 2018
Other comprehensive income
Cumulative effect of adopting ASU No. 2018-02**
December 31, 2019
*We adopted ASU No. 2016-01, "Recognition and Measurement of Financial Assets and Liabilities," beginning January 1, 2018.
**See Note 2—Changes in Accounting Principles for additional information.
(5,646)
586
(5,060)
(642)
-
(5,702)
695
-
(5,007)
(547)
147
(400)
39
-
(361)
51
(40)
(350)
-
(58)
(58)
-
58
-
-
-
-
$
(6,193)
675
(5,518)
(603)
58
(6,063)
746
(40)
(5,357)
During 2019, we recognized $483 million of foreign currency translation adjustments related to the completion
of our sale of two ConocoPhillips U.K. subsidiaries. For additional information related to this disposition, see
Note 5—Asset Acquisitions and Dispositions.
There were no items within accumulated other comprehensive loss related to noncontrolling interests.
The following table summarizes reclassifications out of accumulated other comprehensive loss during the years
ended December 31:
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.
Millions of Dollars
2019
2018
$
$
88
23
189
50
141
Note 21—Cash Flow Information
Noncash Investing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset
retirement obligations
Increase (decrease) in assets and liabilities acquired in a nonmonetary
exchange*
Accounts receivable
Inventories
Investments and long-term receivables
PP&E
Other long-term assets
Accounts payable
Accrued income and other taxes
Cash Payments
Interest
Income taxes
Net Sales (Purchases) of Investments
Short-term investments purchased
Short-term investments sold
Investments and long-term receivables purchased
*See Note 5—Asset Acquisitions and Dispositions.
Millions of Dollars
2019
2018
2017
$
205
395
(37)
-
-
-
-
-
-
-
(44)
42
15
1,907
(9)
7
40
-
-
-
-
-
-
-
$
$
$
810
2,905
772
2,976
1,163
1,168
(4,902)
2,138
(146)
(2,910)
(1,953)
3,573
-
1,620
(6,617)
4,827
-
(1,790)
The following items are included in the “Cash Flows from Operating Activities” section of our consolidated
cash flows.
We collected $330 million and $430 million in 2019 and 2018, respectively, from PDVSA under a settlement
agreement related to an award issued by the ICC Tribunal in 2018. We collected $262 million and $75 million
from Ecuador in 2018 and 2017, respectively, as installment payments related to an agreement reached with
Ecuador in 2017. For more information on these settlements, see Note 13—Contingencies and Commitments.
In 2019, we made a $324 million contribution to our U.K. pension plan. We made discretionary payments to
our domestic qualified pension plan of $120 million and $600 million in 2018 and 2017, respectively.
In 2017, we recognized a $180 million adverse cash impact from the settlement of cross-currency swap
transactions.
142
Note 22—Other Financial Information
Interest and Debt Expense
Incurred
Debt
Other
Capitalized
Expensed
Other Income
Interest income
Unrealized gains (losses) on Cenovus Energy common shares*
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
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
$
$
$
$
$
$
$
$
Millions of Dollars
2019
2018
2017
799
36
835
(57)
778
166
649
543
1,358
838
67
905
(170)
735
97
(437)
513
173
1,114
103
1,217
(119)
1,098
112
-
417
529
82
78
100
1,008
1,075
1,050
-
-
5
-
31
1
21
58
-
-
(11)
(26)
3
-
21
(13)
-
-
3
7
23
1
(3)
31
Millions of Dollars
2019
2018
Properties, Plants and Equipment
$ 88,284 * 100,657
Proved properties
4,662
Unproved properties
5,278
Other
97,746 110,597
Gross properties, plants and equipment
(55,477) * (64,899)
Less: Accumulated depreciation, depletion and amortization
Net properties, plants and equipment
45,698
*Excludes assets classified as held for sale at December 31, 2019. See Note 5—Asset Acquisitions and Dispositions, for additional information.
3,980 *
5,482
$ 42,269
143
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*
*We paid interest to, or received interest from, various affiliates. See Note 6—Investments, Loans and Long-Term Receivables, for additional
information on loans to affiliated companies.
89
38
65
(13)
98
98
60
(14)
$
107
99
59
(13)
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:
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
Consolidated sales and other operating revenues
Millions of Dollars
2019
2018
2017
$
26,106
28,098
20,525
6,558
(97)
32,567
8,218
101
36,417
8,669
(88)
29,106
$
Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at
market prices which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,”
and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy
for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following
disaggregation of revenues is provided in conjunction with Note 25—Segment Disclosures and Related
Information:
Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
Canada
Europe and North Africa
Physical contracts meeting the definition of a derivative
Millions of Dollars
2019
2018
2017
$
$
4,989
691
878
6,558
6,358
629
1,231
8,218
6,302
864
1,503
8,669
144
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
Natural gas
Other
Physical contracts meeting the definition of a derivative
Millions of Dollars
2019
2018
2017
$
$
804
5,313
441
6,558
1,112
6,734
372
8,218
588
7,811
270
8,669
Practical Expedients
Typically, our commodity sales contracts are less than 12 months in duration; however, in certain specific
cases may extend longer, which may be out to the end of field life. We have long-term commodity sales
contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-
based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each
wholly unsatisfied performance obligation within the contract. Accordingly, we have applied the practical
expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price
allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially
unsatisfied) as of the end of the reporting period.
Receivables and Contract Liabilities
Receivables from Contracts with Customers
At December 31, 2019, the “Accounts and notes receivable” line on our consolidated balance sheet included
trade receivables of $2,372 million compared with $2,889 million at December 31, 2018, and included both
contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC
Topic 606. We typically receive payment within 30 days or less (depending on the terms of the invoice) once
delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical gas sales
contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative
under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade
receivables associated with gas sold under contracts for which NPNS has not been elected compared with trade
receivables where NPNS has been elected.
Contract Liabilities from Contracts with Customers
We have entered into contractual arrangements where we license proprietary technology to customers related
to the optimization process for operating LNG plants. The agreements typically provide for negotiated
payments to be made at stated milestones. The payments are not directly related to our performance under the
contract and are recorded as deferred revenue to be recognized as revenue when the customer can utilize and
benefit from their right to use the license. Payments are received in installments over the construction period.
Contract Liabilities
At December 31, 2018
Contractual payments received
Revenue recognized
At December 31, 2019
Millions of
Dollars
$
$
206
73
(199)
80
We expect to recognize the contract liabilities as of December 31, 2019, as revenue during 2021 and 2022.
145
Note 25—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. We manage our operations through six operating segments, which are primarily defined by geographic
region: Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other
International.
Corporate and Other represents costs not directly associated with an operating segment, such as most interest
expense, premiums on early retirement of debt, corporate overhead and certain technology activities, including
licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.
We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips.
Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment sales are at
prices that approximate market.
Analysis of Results by Operating Segment
Sales and Other Operating Revenues
Alaska
Lower 48
Intersegment eliminations
Lower 48
Canada
Intersegment eliminations
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated sales and other operating revenues
Depreciation, Depletion, Amortization and Impairments
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated depreciation, depletion, amortization and impairments
Millions of Dollars
2019
2018
$
$
$
$
5,483
15,514
(46)
15,468
2,910
(1,141)
1,769
5,101
4,525
-
221
32,567
805
3,224
232
887
1,285
-
62
6,495
5,740
17,029
(40)
16,989
3,184
(1,160)
2,024
6,635
4,861
-
168
36,417
760
2,370
324
1,041
1,382
-
106
5,983
2017
4,224
12,968
(4)
12,964
3,178
(559)
2,619
5,181
4,014
-
104
29,106
1,026
6,693
461
1,313
3,819
-
134
13,446
The market for our products is large and diverse, therefore, our sales and other operating revenues are not
dependent upon any single customer.
146
Equity in Earnings of Affiliates
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated equity in earnings of affiliates
Income Taxes
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated income taxes
Net Income (Loss) Attributable to ConocoPhillips
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated net income (loss) attributable to ConocoPhillips
Investments in and Advances to Affiliates
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated investments in and advances to affiliates
Millions of Dollars
2019
7
(159)
-
16
915
-
-
779
472
137
(43)
1,435
491
8
(233)
2,267
1,520
436
279
2,724
1,929
263
38
7,189
83
35
-
54
8,281
-
-
8,453
$
$
$
$
$
$
$
$
2018
2017
6
1
-
16
1,051
-
-
1,074
376
474
(96)
2,265
722
30
(103)
3,668
1,814
1,747
63
1,866
2,070
364
(1,667)
6,257
86
378
-
55
8,821
-
-
9,340
7
5
197
10
553
-
-
772
(689)
(2,453)
(616)
1,165
351
21
399
(1,822)
1,466
(2,371)
2,564
553
(1,098)
167
(2,136)
(855)
56
402
-
55
9,077
-
-
9,590
147
Total Assets
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated total assets
Capital Expenditures and Investments
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated capital expenditures and investments
Interest Income and Expense
Interest income
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
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.
Millions of Dollars
2019
2018
2017
$
$
$
$
$
15,453
14,425
6,350
8,121
14,716
285
11,164
70,514
1,513
3,394
368
708
584
8
61
6,636
-
-
-
2
15
-
149
14,648
14,888
5,748
9,883
16,151
89
8,573
69,980
1,298
3,184
477
877
718
6
190
6,750
-
-
-
2
15
-
80
12,108
14,632
6,214
11,870
16,985
97
11,456
73,362
815
2,136
202
872
482
21
63
4,591
-
-
-
2
9
-
101
$
778
735
1,098
$
$
18,482
8,715
814
4,556
32,567
19,571
10,720
1,114
5,012
36,417
13,260
10,773
1,102
3,971
29,106
148
Geographic Information
Sales and Other Operating Revenues(1)
Long-Lived Assets(2)
2019
2018
2017
2019
2018
2017
Millions of Dollars
21,159
1,647
1,769
772
875
1,103
1,230
2,349
1,649
14
32,567
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 $426 million of net PP&E associated with assets held for sale as of December 31, 2019. See Note 5—
Acquisitions and Dispositions, for additional information.
(4)Long-lived assets do not include $1,236 million of net PP&E associated with assets held for sale as of December 31, 2019. See Note 5—
Acquisitions and Dispositions, for additional information.
22,740
1,798
2,024
836
886
1,142
1,346
2,886
2,606
153
36,417
17,204
1,448
2,619
712
757
586
1,103
2,348
2,248
81
29,106
26,838
9,301
5,333
1,380
669
679
2,327
5,582
1,583
1,346
55,038
26,566
7,228
5,769
1,447
605
668
1,871
5,258
2
1,308
50,722
23,623
9,657
5,613
1,275
758
699
2,736
6,154
3,335
1,423
55,273
$
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.
149
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
150
methods, volumetric-based methods, geologic maps, seismic interpretation, well logs, well test data, core data,
analogy and statistical analysis.
We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and
reporting of proved reserves. This policy is applied by the geoscientists and reservoir engineers in our
business units around the world. As part of our internal control process, each business unit’s reserves
processes and controls are reviewed annually by an internal team which is headed by the company’s Manager
of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geoscientists,
finance personnel and a senior representative from DeGolyer and MacNaughton (D&M), a third-party
petroleum engineering consulting firm, reviews the business units’ reserves for adherence to SEC guidelines
and company policy through on-site visits, teleconferences and review of documentation. In addition to
providing independent reviews, this internal team also ensures reserves are calculated using consistent and
appropriate standards and procedures. This team is independent of business unit line management and is
responsible for reporting its findings to senior management. The team is responsible for communicating our
reserves policy and procedures and is available for internal peer reviews and consultation on major projects or
technical issues throughout the year. All of our proved reserves held by consolidated companies and our share
of equity affiliates have been estimated by ConocoPhillips.
During 2019, our processes and controls used to assess over 90 percent of proved reserves as of December 31,
2019, were reviewed by D&M. The purpose of their review was to assess whether the adequacy and
effectiveness of our internal processes and controls used to determine estimates of proved reserves are in
accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an
overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data
presented included pertinent seismic information, geologic maps, well logs, production tests, material balance
calculations, reservoir simulation models, well performance data, operating procedures and relevant economic
criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective
third-party input on these processes and controls. D&M’s opinion was the general processes and controls
employed by ConocoPhillips in estimating its December 31, 2019, proved reserves for the properties reviewed
are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of this Annual
Report on Form 10-K.
The technical person primarily responsible for overseeing the processes and internal controls used in the
preparation of the company’s reserves estimates is the Manager of Reserves Compliance and Reporting. This
individual holds a master’s degree in petroleum engineering. He is a member of the Society of Petroleum
Engineers with over 25 years of oil and gas industry experience and has held positions of increasing
responsibility in reservoir engineering, subsurface and asset management in the U.S. and several international
field locations.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical
Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results
of Operations for additional discussion of the sensitivities surrounding these estimates.
151
Proved Reserves
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
End of 2017
End of 2018
End of 2019
Crude Oil
Millions of Barrels
Lower Total
Asia Pacific/
Alaska
48
U.S. Canada Europe Middle East Africa
Total
837
113
6
-
41
(60)
-
937
72
2
233
48
(59)
-
1,233
40
7
-
25
(74)
-
1,231
506
65
-
-
210
(64)
(10)
707
(90)
-
1
179
(82)
(12)
703
(36)
-
1
226
(95)
(2)
797
1,343
178
6
-
251
(124)
(10)
1,644
(18)
2
234
227
(141)
(12)
1,936
4
7
1
251
(169)
(2)
2,028
13
1
-
-
-
(1)
(12)
1
2
-
-
2
(1)
-
4
(1)
-
-
2
-
-
5
303
38
-
-
-
(45)
-
296
24
-
-
2
(40)
(36)
246
18
-
-
-
(36)
(30)
198
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
185
32
-
-
2
(34)
-
185
6
-
-
1
(33)
-
159
(5)
-
-
11
(31)
-
134
88
-
-
-
-
(5)
-
83
-
-
-
-
(5)
-
78
-
-
-
-
(5)
-
73
203
-
-
-
-
(7)
-
196
5
-
-
-
(13)
-
188
23
-
-
-
(14)
-
197
2,047
249
6
-
253
(211)
(22)
2,322
19
2
234
232
(228)
(48)
2,533
39
7
1
264
(250)
(32)
2,562
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
88
-
-
-
-
(5)
-
83
-
-
-
-
(5)
-
78
-
-
-
-
(5)
-
73
837
937
1,233
1,231
506
707
703
797
1,343
1,644
1,936
2,028
152
13
1
4
5
303
296
246
198
273
268
237
207
203
196
188
197
2,135
2,405
2,611
2,635
Years Ended
December 31
Developed
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Undeveloped
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Crude Oil
Millions of Barrels
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Africa
Total
747
828
1,058
1,048
256
315
346
334
1,003
1,143
1,404
1,382
-
-
-
-
90
109
175
183
-
-
-
-
-
-
-
-
250
392
357
463
-
-
-
-
-
-
-
-
340
501
532
646
-
-
-
-
13
1
2
3
-
-
-
-
-
-
2
2
-
-
-
-
184
190
192
149
-
-
-
-
119
106
54
49
-
-
-
-
106
121
113
94
88
83
78
73
79
64
46
40
-
-
-
-
203
196
185
181
1,509
1,651
1,896
1,809
-
-
-
-
-
-
3
16
-
-
-
-
88
83
78
73
538
671
637
753
-
-
-
-
Notable changes in proved crude oil reserves in the three years ended December 31, 2019, included:
• Revisions: In 2019, Alaska upward revisions were due to cost and technical revisions of 74 million barrels, partially
offset by downward price revisions of 34 million barrels. Upward revisions in Europe and Africa were primarily due to
infill drilling and technical revisions. Downward revisions in Lower 48 were due to changes in development timing for
specific well locations from the unconventional plays of 71 million barrels and price revisions of 22 million barrels,
partially offset by upward revisions related to infill drilling and improved well performance of 57 million barrels.
In 2018, downward revisions in Lower 48 were primarily due to changes in development timing for specific well
locations from the unconventional plays and are more than offset by increases in planned well locations in the
unconventional plays in the extensions and discoveries category. Downward revisions in Lower 48 due to development
timing were partially offset by higher prices. Revisions in Alaska, Europe and Asia Pacific/Middle East were primarily
due to higher prices.
In 2017, revisions in Alaska, Lower 48, Europe and Asia Pacific/Middle East were primarily due to higher prices.
• Purchases: In 2018, Alaska purchases were due to the Greater Kuparuk Area and Western North Slope acquisitions.
153
• 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.
154
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
End of 2017
End of 2018
End of 2019
Natural Gas Liquids
Millions of Barrels
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
107
4
-
-
-
(5)
-
106
5
-
-
-
(5)
-
106
(1)
-
-
-
(5)
-
100
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
278
29
-
-
71
(24)
(130)
224
(25)
-
-
69
(25)
(21)
222
(11)
-
-
62
(28)
-
245
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
385
33
-
-
71
(29)
(130)
330
(20)
-
-
69
(30)
(21)
328
(12)
-
-
62
(33)
-
345
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
48
-
-
-
-
(3)
(44)
1
-
-
-
-
-
-
1
-
-
-
1
-
-
2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
19
2
-
-
-
(3)
-
18
1
-
-
1
(3)
-
17
3
-
-
-
(3)
(4)
13
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
107
106
106
100
278
224
222
245
385
330
328
345
48
1
1
2
19
18
17
13
155
5
1
-
-
1
(2)
-
5
(1)
-
-
-
(1)
-
3
(1)
-
-
-
(1)
-
1
47
-
-
-
-
(2)
-
45
-
-
-
-
(3)
-
42
-
-
-
-
(3)
-
39
52
50
45
40
Total
457
36
-
-
72
(37)
(174)
354
(20)
-
-
70
(34)
(21)
349
(10)
-
-
63
(37)
(4)
361
47
-
-
-
-
(2)
-
45
-
-
-
-
(3)
-
42
-
-
-
-
(3)
-
39
504
399
391
400
Years Ended
December 31
Developed
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Undeveloped
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Natural Gas Liquids
Millions of Barrels
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Total
107
106
106
100
-
-
-
-
-
-
-
-
-
-
-
-
209
101
97
99
-
-
-
-
69
123
125
146
-
-
-
-
316
207
203
199
-
-
-
-
69
123
125
146
-
-
-
-
47
1
-
1
-
-
-
-
1
-
1
1
-
-
-
-
15
16
15
10
-
-
-
-
4
2
2
3
-
-
-
-
5
2
3
1
47
45
42
39
-
3
-
-
-
-
-
-
383
226
221
211
47
45
42
39
74
128
128
150
-
-
-
-
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.
156
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
End of 2017
End of 2018
End of 2019
Natural Gas
Billions of Cubic Feet
Lower Total
Asia Pacific/
Alaska
48
U.S. Canada Europe Middle East Africa
Total
2,102
287
-
-
2
(71)
-
2,320
150
-
335
2
(71)
-
2,736
30
-
-
7
(85)
-
2,688
4,714
460
-
-
582
(338)
(2,885)
2,533
(283)
-
1
527
(237)
(223)
2,318
(113)
-
2
483
(252)
(7)
2,431
6,816
747
-
-
584
(409)
(2,885)
4,853
(133)
-
336
529
(308)
(223)
5,054
(83)
-
2
490
(337)
(7)
5,119
1,037
8
-
-
3
(71)
(966)
11
9
-
-
11
(5)
-
26
(2)
-
-
23
(4)
-
43
1,238
167
-
-
-
(188)
-
1,217
86
-
-
110
(188)
(13)
1,212
160
-
-
-
(178)
(298)
896
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,102
2,320
2,736
2,688
4,714
2,533
2,318
2,431
6,816
4,853
5,054
5,119
1,037
11
26
43
1,238
1,217
1,212
896
157
1,526
16
-
-
23
(267)
-
1,298
4
-
-
23
(246)
-
1,079
147
-
-
1
(250)
-
977
4,381
111
-
-
185
(374)
-
4,303
280
-
-
362
(381)
-
4,564
(7)
-
-
252
(388)
-
4,421
5,907
5,601
5,643
5,398
227
-
-
-
-
(3)
-
224
-
-
-
-
(10)
-
214
21
-
-
-
(11)
-
224
10,844
938
-
-
610
(938)
(3,851)
7,603
(34)
-
336
673
(757)
(236)
7,585
243
-
2
514
(780)
(305)
7,259
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
4,381
111
-
-
185
(374)
-
4,303
280
-
-
362
(381)
-
4,564
(7)
-
-
252
(388)
-
4,421
227
224
214
224
15,225
11,906
12,149
11,680
Years Ended
December 31
Developed
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Undeveloped
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Natural Gas
Billions of Cubic Feet
Lower Total
Asia Pacific/
Alaska
48
U.S. Canada Europe Middle East Africa
Total
2,094
2,310
2,720
2,601
4,199
1,597
1,427
1,398
6,293
3,907
4,147
3,999
1,031
11
17
30
998
997
1,052
697
-
-
-
-
-
-
-
-
-
-
-
-
8
10
16
87
515
936
891
1,033
523
946
907
1,120
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
6
-
9
13
-
-
-
-
-
-
-
-
240
220
160
199
-
-
-
-
1,188
945
758
843
4,110
4,044
4,059
3,898
338
353
321
134
271
259
505
523
227
224
214
224
9,737
6,084
6,188
5,793
-
-
-
-
-
-
-
-
-
-
-
-
4,110
4,044
4,059
3,898
1,107
1,519
1,397
1,466
271
259
505
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.
158
• 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.
159
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
End of 2017
End of 2018
End of 2019
160
Bitumen
Millions of Barrels
Canada
159
16
-
-
96
(21)
-
250
10
-
-
-
(24)
-
236
37
-
-
31
(22)
-
282
1,089
-
-
-
-
(23)
(1,066)
-
-
-
-
-
-
-
-
-
-
-
-
-
1,248
250
236
282
Years Ended
December 31
Developed
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Undeveloped
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Bitumen
Millions of Barrels
Canada
159
154
155
187
322
-
-
-
-
96
81
95
767
-
-
-
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.
161
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2016
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
End of 2017
End of 2018
End of 2019
Total Proved Reserves
Millions of Barrels of Oil Equivalent
Lower Total
Asia Pacific/
Alaska
48
U.S. Canada Europe Middle East Africa
Total
1,294
166
6
-
41
(77)
-
1,430
102
2
289
48
(76)
-
1,795
44
7
-
26
(93)
-
1,779
1,570
170
-
-
378
(144)
(621)
2,864
336
6
-
419
(221)
(621)
1,353
2,783
1,312
3,107
(161)
-
1
335
(146)
(70)
(59)
2
290
383
(222)
(70)
(67)
-
2
368
(165)
(3)
(23)
7
2
394
(258)
(3)
1,447
3,226
393
18
-
-
97
(37)
(217)
254
12
-
-
4
(25)
-
245
36
-
-
38
(23)
-
296
528
68
-
-
-
(79)
-
517
40
-
-
21
(75)
(38)
465
48
-
-
-
(68)
(85)
360
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,089
-
-
-
-
(23)
(1,066)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
444
36
-
-
7
(81)
-
406
5
-
-
6
(75)
-
342
19
-
-
11
(74)
-
298
865
18
-
-
31
(69)
-
845
46
-
-
60
(71)
-
880
(1)
-
-
42
(73)
-
848
241
-
-
-
-
(8)
-
233
6
-
-
-
(15)
-
224
26
-
-
-
(16)
-
234
4,470
458
6
-
523
(426)
(838)
4,193
4
2
290
414
(412)
(108)
4,383
106
7
2
443
(439)
(88)
4,414
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,954
18
-
-
31
(92)
(1,066)
845
46
-
-
60
(71)
-
880
(1)
-
-
42
(73)
-
848
1,294
1,430
1,795
1,779
1,570
1,353
1,312
1,447
2,864
2,783
3,107
3,226
1,482
254
245
296
528
517
465
360
1,309
1,251
1,222
1,146
241
233
224
234
6,424
5,038
5,263
5,262
162
Years Ended
December 31
Developed
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Undeveloped
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
End of 2018
End of 2019
Total Proved Reserves
Millions of Barrels of Oil Equivalent
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Africa
Total
1,203
1,319
1,617
1,582
1,165
682
681
666
2,368
2,001
2,298
2,248
-
-
-
-
91
111
178
197
-
-
-
-
-
-
-
-
405
671
631
781
-
-
-
-
-
-
-
-
496
782
809
978
-
-
-
-
391
158
160
197
322
-
-
-
2
96
85
99
767
-
-
-
365
372
382
275
-
-
-
-
163
145
83
85
-
-
-
-
309
281
244
236
820
802
796
761
135
125
98
62
45
43
84
87
241
233
221
218
3,674
3,045
3,305
3,174
-
-
-
-
1,142
802
796
761
-
-
3
16
796
1,148
1,078
1,240
-
-
-
-
812
43
84
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:
End of 2018
Transfers to proved developed
Revisions
Improved recovery
Purchases
Extensions and discoveries
Sales
End of 2019
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
1,162
(286)
(5)
7
1
468
(20)
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.
163
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.
164
Results of Operations
Year Ended
December 31, 2019
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Equity affiliates
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Alaska
Lower Total
Other
48 U.S. Canada Europe Middle East Africa Areas
Asia Pacific/
Total
Millions of Dollars
$
$
$
$
4,883
4
(629)
61
4,319
1,235
308
97
6,356
-
-
78
6,434
1,578
437
430
11,239
4
(629)
139
10,753
2,813
745
527
709
-
-
86
795
380
18
32
3,207
-
-
1,785
4,992
741
32
69
3,032
449
(41)
12
3,452
619
54
80
919
-
-
101
1,020
70
3
5
-
-
-
326
326
(8)
(2)
33
19,106
453
(670)
2,449
21,338
4,615
850
746
700
-
(12)
62
1,929
444
1,485
2,804
402
116
49
618
147
471
3,504
402
104
111
2,547
591
1,956
230
2
(38)
7
164
(74)
238
842
1
(42)
142
3,207
591
2,616
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,172
-
58
43
1,426
458
968
599
2,229
-
31
2,859
335
820
-
579
-
11
16
1,098
170
928
37
-
22
-
883
833
50
-
-
10
-
293
7
286
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
5,785
405
114
303
8,520
2,406
6,114
599
2,229
-
31
2,859
335
820
-
579
-
11
16
1,098
170
928
165
Total
20,547
550
(767)
1,997
22,327
4,480
941
372
5,497
10
54
331
10,642
3,726
6,916
758
2,018
-
(6)
2,770
321
804
-
640
-
(4)
15
994
103
891
$
$
$
Year Ended
December 31, 2018
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Equity affiliates
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
$
Alaska
Lower Total
Other
48 U.S. Canada Europe Middle East Africa Areas
Asia Pacific/
Millions of Dollars
4,816
5
(722)
335
4,434
964
357
59
616
1
16
56
2,365
419
1,946
-
-
213
6,573 11,389
5
(722)
548
6,786 11,220
2,497
1,533
789
432
235
176
2,279
64
63
51
2,188
466
1,722
2,895
65
79
107
4,553
885
3,668
582
-
-
164
746
417
21
21
313
9
56
7
(98)
(114)
16
4,449
-
-
737
5,186
856
33
57
1,070
(78)
(62)
178
3,132
1,354
1,778
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
3,177
545
(45)
6
3,683
646
95
43
1,186
14
(19)
39
1,679
683
996
758
2,018
-
(6)
2,770
321
804
-
640
-
(4)
15
994
103
891
950
-
-
110
1,060
62
3
(4)
33
-
1
-
965
926
39
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
432
432
2
-
20
-
-
(1)
-
411
(8)
419
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
166
Year Ended
December 31, 2017
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Equity affiliates
Sales
Transfers
Transportation costs
Other revenues
Total revenues
Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and
amortization
Impairments
Other related expenses
Accretion
Income tax provision (benefit)
Results of operations
Alaska
Lower
48
Total
Other
U.S. Canada Europe Middle East Africa Areas
Asia Pacific/
Millions of Dollars
$ 3,542
4
(706)
14
2,854
947
275
83
730
179
(7)
52
595
(669)
$ 1,264
4,557
-
-
28
4,585
1,607
318
584
2,685
3,969
62
63
(4,703)
(2,401)
(2,302)
8,099
4
(706)
42
7,439
2,554
593
667
3,415
4,148
55
115
(4,108)
(3,070)
(1,038)
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
705
-
-
2,158
2,863
604
33
22
438
22
7
16
1,721
(651)
2,372
528
-
-
5
533
174
7
1
150
-
4
2
195
26
169
3,527
-
-
68
3,595
770
32
45
1,234
46
57
172
1,239
702
537
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,752
411
(80)
11
3,094
566
39
97
1,283
-
60
37
1,012
363
649
563
1,398
-
-
1,961
363
604
1,699
617
1,717
22
11
(3,072)
(998)
(2,074)
487
-
-
48
535
44
2
61
16
-
6
-
406
428
(22)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
322
322
(1)
-
45
-
-
-
-
278
11
267
-
-
-
-
-
-
-
-
-
-
19
-
(19)
13
(32)
Total
15,570
415
(786)
2,649
17,848
4,537
699
937
6,386
4,216
185
340
548
(2,217)
2,765
1,091
1,398
-
5
2,494
537
611
1,700
767
1,717
45
13
(2,896)
(959)
(1,937)
167
Statistics
Net Production
Crude Oil
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
Greater Prudhoe Area (Alaska)*
Natural Gas Liquids
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
Greater Prudhoe Area (Alaska)*
Bitumen
Consolidated operations—Canada
Equity affiliates—Canada
Total company
Natural Gas
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
Greater Prudhoe Area (Alaska)*
2019
Thousands of Barrels Daily
2018
2017
202
266
468
1
100
85
38
692
13
705
66
15
81
96
-
7
4
107
8
115
15
60
60
171
229
400
1
113
89
36
639
14
653
71
14
69
83
1
8
3
95
7
102
14
66
66
167
180
347
3
122
93
20
585
14
599
74
14
69
83
9
8
4
104
7
111
14
59
63
122
Millions of Cubic Feet Daily
7
622
629
9
447
637
31
1,753
1,052
2,805
4
6
596
602
12
475
626
28
1,743
1,031
2,774
5
7
898
905
187
476
687
8
2,263
1,007
3,270
5
*At year-end 2019, the Greater Prudhoe Area in Alaska contained more than 15% of total proved reserves.
168
Average Sales Prices
2019
2018
2017
Crude Oil Per Barrel
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total operations
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total operations
Bitumen Per Barrel
Consolidated operations—Canada
Equity affiliates—Canada
$
$
55.85
55.30
55.54
40.87
65.12
65.02
64.47
64.85
58.51
61.32
58.57
16.83
16.85
19.87
29.37
37.85
32.29
18.73
36.70
20.09
60.23
62.99
61.75
48.73
70.98
70.93
69.83
70.67
65.01
72.49
65.17
27.30
27.30
43.70
36.87
47.20
40.00
29.03
45.69
30.48
$
31.72
22.29
42.69
47.36
45.01
43.69
54.04
54.38
55.11
54.16
48.70
54.76
48.84
22.20
22.20
21.51
34.07
41.37
30.34
24.21
38.74
25.22
21.43
23.83
$
Natural Gas Per Thousand Cubic Feet
Consolidated operations
2.72
Alaska
2.73
Lower 48
2.73
United States
1.93
Canada
5.72
Europe
4.66
Asia Pacific/Middle East
3.53
Africa
4.64
Total international
3.87
Total consolidated operations
4.27
Equity affiliates—Asia Pacific/Middle East
Total operations
4.00
Average sales prices for Alaska crude oil and Asia Pacific/Middle East natural gas above reflect a reduction for transportation costs in which we
have an ownership interest that are incurred subsequent to the terminal point of the production function. Accordingly, the average sales prices
differ from those discussed in Item 7 of Management's Discussion and Analysis of Financial Condition and Results of Operations.
3.19
2.12
2.12
0.49
4.92
5.73
4.87
5.35
4.19
6.29
4.99
2.48
2.82
2.82
1.00
7.79
5.95
4.84
6.64
5.33
6.06
5.60
169
2019
2018
2017
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Total equity affiliates
Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada
Equity affiliates—Canada
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Total equity affiliates
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total international
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Total equity affiliates
*Includes bitumen.
$
15.52
9.59
11.52
16.53
11.22
8.74
4.46
10.26
10.99
4.68
4.68
14.20
10.58
11.73
16.32
11.73
9.03
4.14
10.72
11.26
4.56
4.56
$
13.74
13.59
$
$
3.87
2.65
3.05
0.78
0.48
0.76
0.19
0.60
2.03
5.26
2.98
3.71
0.82
0.45
1.33
0.20
0.82
2.37
11.46
11.46
11.41
11.41
8.80
17.03
14.35
10.00
12.75
16.55
2.36
12.99
13.78
8.09
8.09
9.07
15.73
13.60
12.25
14.66
16.58
2.21
14.06
13.82
9.09
9.09
14.26
11.03
12.04
16.22
10.09
7.31
5.74
9.99
11.05
7.57
5.26
5.84
14.63
18.74
4.14
2.18
2.80
0.89
0.42
0.50
0.26
0.53
1.70
0.30
8.76
6.64
10.99
18.44
16.10
11.76
16.18
16.58
2.09
14.96
15.55
6.52
8.94
8.34
170
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
Exploratory
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates
Development
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Canada
Asia Pacific/Middle East
Other areas
Total equity affiliates
*Our total proportionate interest was less than one.
Productive
2018
2019
2017
2019
2018
2017
Dry
-
13
13
13
*
1
-
-
27
14
14
9
161
170
13
7
8
-
-
198
19
84
-
103
-
6
6
-
1
1
-
-
8
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1
1
-
*
-
*
-
1
2
2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
3
3
-
*
1
-
1
5
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
7
35
42
-
1
1
-
-
44
8
8
12
255
267
2
6
21
2
-
298
-
106
-
106
6
45
51
2
*
2
-
-
55
6
6
11
254
265
1
9
12
1
-
288
-
75
-
75
171
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
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates
In Progress
Gross
Net
Oil
Gross
Productive
Gas
Net
Gross
Net
4
349
353
32
19
12
13
14
443
325
325
4
170
174
32
1
6
2
7
222
79
79
1,656
10,070
11,726
186
469
302
840
-
13,523
-
-
997
4,547
5,544
93
79
143
137
-
5,996
-
-
-
4,329
4,329
31
55
56
7
-
4,478
4,307
4,307
-
1,704
1,704
27
2
28
1
-
1,762
1,051
1,051
Acreage at December 31, 2019
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates
Thousands of Acres
Developed
Gross
Net
Undeveloped
Gross
Net
651
2,569
3,220
206
430
1,538
358
-
5,752
467
2,012
2,479
126
50
721
58
-
3,434
1,331
10,337
11,668
3,270
2,102
9,910
12,545
1,400
40,895
1,320
8,396
9,716
1,798
610
5,735
2,049
742
20,650
933
933
229
229
3,723
3,723
840
840
172
Costs Incurred
Year Ended
December 31
2019
Consolidated operations
Unproved property acquisition
Proved property acquisition
Exploration
Development
Equity affiliates
Unproved property acquisition
Proved property acquisition
Exploration
Development
2018
Consolidated operations
Unproved property acquisition
Proved property acquisition
Exploration
Development
Equity affiliates
Unproved property acquisition
Proved property acquisition
Exploration
Development
2017
Consolidated operations
Unproved property acquisition
Proved property acquisition
Exploration
Development
Equity affiliates
Unproved property acquisition
Proved property acquisition
Exploration
Development
Alaska
Lower
48
Total
U.S.
Millions of Dollars
Asia Pacific/
Canada
Europe
Middle East Africa
Other
Areas
$
101
1
102
281
1,125
$ 1,508
45
116
161
390
3,028
3,579
146
117
263
671
4,153
5,087
14
-
14
200
215
429
-
-
-
119
625
744
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
119
2,227
2,346
203
718
$ 3,267
126
16
142
500
2,715
3,357
245
2,243
2,488
703
3,433
6,624
126
6
132
90
301
523
-
-
-
65
703
768
$
$
$
$
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
18
-
18
74
736
828
267
35
302
399
1,559
2,260
285
35
320
473
2,295
3,088
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
76
-
76
56
102
234
-
-
-
6
150
156
-
-
-
-
-
-
-
-
-
52
784
836
-
-
-
-
-
-
173
-
115
115
66
486
667
62
-
62
23
171
256
-
-
-
82
773
855
-
-
-
22
206
228
15
-
15
139
388
542
-
-
-
38
403
441
-
-
-
8
22
30
-
-
-
-
-
-
-
-
-
(6)
16
10
-
-
-
-
-
-
-
-
-
61
10
71
-
-
-
-
-
-
Total
357
232
589
1,103
5,501
7,193
62
-
62
23
171
256
197
-
197
39
-
236
-
-
-
-
-
-
-
-
-
41
-
41
371
2,249
2,620
975
5,226
8,821
-
-
-
-
-
-
-
-
-
42
-
42
-
-
-
-
-
-
-
-
-
22
206
228
376
35
411
823
3,579
4,813
-
-
-
44
553
597
Capitalized Costs
At December 31
2019
Consolidated operations
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
Equity affiliates
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
2018
Consolidated operations
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
Equity affiliates
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
Lower Total
Asia Pacific/
Alaska
48
U.S. Canada Europe Middle East
Other
Africa Areas
Total
Millions of Dollars
$ 20,957
1,429
22,386
37,491 58,448
2,484
38,546 60,932
1,055
6,673 14,113
1,149
87
7,822 14,200
9,419
$ 12,967
26,294 35,713
12,252 25,219
2,050
5,772
9,017
5,183
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
14,566
501
15,067
10,253
4,814
9,996
2,223
12,219
6,390
5,829
924
123
1,047
379
668
-
-
-
-
-
-
290
290
9
281
-
-
-
-
-
94,724
4,634
99,358
57,421
41,937
9,996
2,223
12,219
6,390
5,829
$ 20,154
1,184
21,338
35,269 55,423
2,309
36,394 57,732
1,125
5,946 23,520
1,083
188
7,029 23,708
14,866
874
15,740
902
119
1,021
- 100,657
89
4,662
89 105,319
9,055
$ 12,283
23,999 33,054
12,395 24,678
1,692 16,591
7,117
5,337
9,974
5,766
342
679
9
80
61,662
43,657
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9,990
2,162
12,152
5,960
6,192
-
-
-
-
-
-
-
-
-
-
9,990
2,162
12,152
5,960
6,192
174
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
2019
Consolidated operations
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Equity affiliates
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Total company
Discounted future net cash flows
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Africa
Total
Millions of Dollars
$ 70,341
53,400
123,741
8,244
16,919
13,084
15,582
177,570
40,464
9,721
3,904
16,252
6,571
$ 9,681
22,194
14,083
2,793
14,330
4,311
10,019
62,658
23,804
6,697
30,582
10,882
19,700
4,525
577
-
3,142
1,198
1,944
5,843
4,143
4,201
2,732
558
2,174
5,162
2,179
1,931
3,812
835
2,977
1,314
484
12,747
1,037
460
577
79,502
31,187
25,576
41,305
13,933
27,372
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
31,671
-
31,671
16,157
1,218
3,086
11,210
4,040
7,170
-
-
-
-
-
-
16,157
1,218
3,086
11,210
4,040
7,170
$ 9,681
10,019
19,700
1,944
2,174
10,147
577
34,542
175
2018
Consolidated operations
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Equity affiliates
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Total company
Discounted future net cash flows
2017
Consolidated operations
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Equity affiliates
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions
Future net cash flows
10 percent annual discount
Discounted future net cash flows
Total company
Discounted future net cash flows
Alaska
Lower
48
Total
U.S.
Millions of Dollars
Asia Pacific/
Canada
Europe
Middle East Africa
Total
$ 82,072
56,922
138,994
6,039
26,989
16,368
16,434
204,824
5,538
42,755 21,363
10,053 12,136
4,418
23,726 19,005
6,461
10,349
12,544
$ 13,377
64,118
22,189
9,956
42,731
16,810
25,921
4,099
606
-
1,334
426
908
8,567
7,608
7,102
3,712
371
3,341
5,705
1,995
2,873
5,795
1,132
4,663
1,336
507
13,492
1,099
498
601
83,825
32,905
33,423
54,671
19,237
35,434
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
33,606
16,449
1,228
3,147
12,782
4,853
7,929
-
-
-
-
-
-
-
33,606
16,449
1,228
3,147
12,782
4,853
7,929
$ 13,377
12,544
25,921
908
3,341
12,592
601
43,363
Lower
Alaska
48
Total
U.S. Canada Europe Middle East Africa
Asia Pacific/
Total
Millions of Dollars
$ 44,969 44,556
89,525
5,479
23,137
15,207
13,181
146,529
53
29,524 18,947
7,255 10,881
2,375
8,137 12,353
4,358
2,712
7,995
5,425
$
48,471
18,136
2,428
20,490
7,070
13,420
4,417
696
-
366
78
288
8,128
8,758
3,333
2,918
289
2,629
5,398
2,511
2,459
4,839
1,032
3,807
1,401
537
10,356
887
422
465
67,815
30,638
18,576
29,500
8,891
20,609
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
23,222
-
23,222
12,984
1,444
2,083
6,711
2,316
4,395
-
-
-
-
-
-
12,984
1,444
2,083
6,711
2,316
4,395
$
5,425
7,995
13,420
288
2,629
8,202
465
25,004
176
Sources of Change in Discounted Future Net Cash Flows
Consolidated Operations
2019
2018
2017
Millions of Dollars
Equity Affiliates
Total Company
2019
2018
2017
2019
2018
2017
Discounted future net cash flows
$
at the beginning of the year
Changes during the year
Revenues less production
costs for the year
Net change in prices and
production costs
Extensions, discoveries and
improved recovery, less
estimated future costs
Development costs for the year
Changes in estimated future
development costs
Purchases of reserves in place,
less estimated future costs
Sales of reserves in place,
less estimated future costs
Revisions of previous quantity
estimates
Accretion of discount
Net change in income taxes
Total changes
Discounted future net cash flows
at year end
$
35,434
20,609
8,151
7,929
4,395
3,937
43,363
25,004
12,088
(13,424) (14,909)
(9,844)
(1,673)
(1,651)
(1,341)
(15,097)
(16,560)
(11,185)
(13,538) 25,391
19,310
(422)
4,559
2,750
(13,960)
29,950
22,060
2,985
5,333
4,574
5,197
1,445
3,653
559
(1,141)
1,225
10
3,033
-
(1,997)
(1,531)
(855)
(365)
2,099
3,055
5,144
(8,479)
4,767
(8,062) 14,825
2,300
1,313
(6,089)
12,458
260
239
(21)
-
-
69
869
(80)
(759)
382
271
(4)
426
3,245
5,572
4,956
5,468
1,441
4,079
14
(64)
538
(1,127)
1,161
-
-
62
485
(588)
3,534
-
10
3,033
-
(786)
(1,997)
(1,531)
(1,641)
(648)
413
(288)
458
2,168
6,013
4,687
(8,821)
(303)
3,540
(9,067)
18,359
1,652
1,726
(6,377)
12,916
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.
177
Selected Quarterly Financial Data (Unaudited)
Sales and
Other
Operating
Revenues
$
9,150
7,953
7,756
7,708
Millions of Dollars
Income (Loss)
Before
Income Taxes
Net
Income
(Loss)
Net Income
(Loss)
Attributable to
ConocoPhillips
Per Share of Common Stock
Net Income (Loss)
Attributable
to ConocoPhillips
Basic
Diluted
2,687
2,058
3,493
1,286
1,846
1,597
3,071
743
1,833
1,580
3,056
720
1.61
1.40
2.76
0.66
1.60
1.40
2.74
0.66
2019
First
Second
Third
Fourth
2018
First
Second
Third
Fourth
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.
$ 8,798
8,504
9,449
9,666
900
1,654
1,873
1,878
888
1,640
1,861
1,868
1,776
2,619
2,906
2,672
0.75
1.40
1.60
1.62
0.75
1.39
1.59
1.61
178
Supplementary Information—Condensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources
LLC, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by
ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company.
ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment
obligations of Burlington Resources LLC, with respect to its publicly held debt securities. Similarly,
ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company
with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and
unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt
securities. All guarantees are joint and several. The following condensed consolidating financial information
presents the results of operations, financial position and cash flows for:
• ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC (in each case, reflecting
investments in subsidiaries utilizing the equity method of accounting).
• All other nonguarantor subsidiaries of ConocoPhillips.
• The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.
In 2017, ConocoPhillips Company received a $9.8 billion return of capital and a $1.4 billion loan repayment
from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had
no impact on our consolidated financial statements.
In 2017, ConocoPhillips received a $7.8 billion return of capital and a $0.2 billion return of earnings from
ConocoPhillips Company to settle certain accumulated intercompany balances. These transactions had no
impact on our consolidated financial statements.
In 2018, ConocoPhillips Company received a $4.8 billion return of earnings and a $2.4 billion loan repayment
from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had
no impact on our consolidated financial statements.
In 2018, ConocoPhillips received a $3.5 billion return of capital and a $1.0 billion return of earnings from
ConocoPhillips Company to settle certain accumulated intercompany balances. These transactions had no
impact on our consolidated financial statements.
In 2019, ConocoPhillips received a $2.4 billion return of capital and a $1.7 billion return of earnings from
ConocoPhillips Company to settle certain accumulated intercompany balances. This transaction had no impact
on our consolidated financial statements.
In 2019, ConocoPhillips Company received a $4.5 billion return of earnings and a $4.2 billion return of capital
from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had
no impact on our consolidated financial statements.
In 2019, Burlington Resources LLC received a $3.2 billion return of earnings from nonguarantor subsidiaries
to settle certain accumulated intercompany balances. These transactions had no impact on our consolidated
financial statements.
This condensed consolidating financial information should be read in conjunction with the accompanying
consolidated financial statements and notes.
179
Income Statement
Revenues and Other Income
Sales and other operating revenues
Equity in earnings of affiliates
Gain (loss) on dispositions
Other income
Intercompany revenues
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 losses
Other expenses
Total Costs and Expenses
Income before income taxes
Income tax provision (benefit)
Net income
Less: net income attributable to noncontrolling interests
Net Income Attributable to ConocoPhillips
Comprehensive Income Attributable to ConocoPhillips
Income Statement
Revenues and Other Income
Sales and other operating revenues
Equity in earnings of affiliates
Gain on dispositions
Other income (loss)
Intercompany revenues
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
Other expenses
Total Costs and Expenses
Income before income taxes
Income tax provision (benefit)
Net income
Less: net income attributable to noncontrolling interests
Net Income Attributable to ConocoPhillips
Comprehensive Income Attributable to ConocoPhillips
See Notes to Consolidated Financial Statements.
Millions of Dollars
Year Ended December 31, 2019
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
$
$
$
-
7,419
-
1
-
7,420
-
1
9
-
-
-
-
-
283
-
-
293
7,127
(62)
7,189
-
7,189
14,510
5,281
2,786
875
113
23,565
12,838
1,380
421
422
596
157
139
16
544
21
60
16,594
6,971
(448)
7,419
-
7,419
-
1,610
-
5
40
1,655
-
1
-
-
-
-
-
-
133
-
-
134
1,521
(46)
1,567
-
1,567
18,057
775
(820)
477
5,542
24,031
4,038
4,345
131
321
5,494
248
814
310
69
45
5
15,820
8,211
2,823
5,388
(68)
-
(14,306)
-
-
(5,695)
(20,001)
(5,034)
(405)
(5)
-
-
-
-
-
(251)
-
-
(5,695)
(14,306)
-
(14,306)
-
32,567
779
1,966
1,358
-
36,670
11,842
5,322
556
743
6,090
405
953
326
778
66
65
27,146
9,524
2,267
7,257
(68)
5,320
(14,306)
7,189
7,935
8,165
1,873
6,058
(16,096)
7,935
Year Ended December 31, 2018
-
6,503
-
-
35
6,538
-
-
8
-
-
-
-
-
295
46
-
349
6,189
(68)
6,257
-
6,257
16,113
8,142
239
(384)
162
24,272
14,591
1,023
289
170
584
(10)
143
17
613
(12)
349
17,757
6,515
12
6,503
-
6,503
-
1,953
-
-
43
1,996
-
4
-
-
-
-
-
-
46
116
6
172
1,824
(41)
1,865
-
1,865
20,304
1,072
824
557
5,627
28,384
5,131
4,245
109
199
5,372
37
905
336
156
(167)
20
16,343
12,041
3,765
8,276
(48)
-
(16,596)
-
-
(5,867)
(22,463)
(5,428)
(59)
(5)
-
-
-
-
-
(375)
-
-
(5,867)
(16,596)
-
(16,596)
-
36,417
1,074
1,063
173
-
38,727
14,294
5,213
401
369
5,956
27
1,048
353
735
(17)
375
28,754
9,973
3,668
6,305
(48)
8,228
(16,596)
6,257
5,654
5,900
1,364
7,961
(15,225)
5,654
180
Income Statement
Revenues and Other Income
Sales and other operating revenues
Equity in earnings (losses) of affiliates
Gain on dispositions
Other income
Intercompany revenues
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
Other expenses
Total Costs and Expenses
Income (Loss) before income taxes
Income tax provision (benefit)
Net income (loss)
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips
Comprehensive Income (Loss) Attributable to ConocoPhillips
See Notes to Consolidated Financial Statements.
Millions of Dollars
Year Ended December 31, 2017
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
$
$
-
(454)
-
2
48
(404)
-
-
9
-
-
-
-
-
420
(43)
267
653
(1,057)
(202)
(855)
-
(855)
12,433
2,047
916
35
291
15,722
11,145
813
342
542
855
1,159
140
32
664
11
190
15,893
(171)
283
(454)
-
(454)
-
886
-
-
13
899
-
-
-
-
-
-
1
-
52
(137)
-
(84)
983
(337)
1,320
-
1,320
16,673
770
1,261
492
3,369
22,565
4,580
4,366
82
392
5,990
5,442
668
330
410
204
(6)
22,458
107
(1,566)
1,673
(62)
1,611
-
(2,477)
-
-
(3,721)
(6,198)
(3,250)
(17)
(6)
-
-
-
-
-
(448)
-
-
(3,721)
(2,477)
-
(2,477)
-
(2,477)
29,106
772
2,177
529
-
32,584
12,475
5,162
427
934
6,845
6,601
809
362
1,098
35
451
35,199
(2,615)
(1,822)
(793)
(62)
(855)
(180)
221
1,672
2,275
(4,168)
(180)
181
Balance Sheet
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments, loans and long-term receivables*
Net properties, plants and equipment
Other assets
Total Assets
Liabilities and Stockholders’ Equity
Accounts payable
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
Retained earnings
Other common stockholders’ equity
Noncontrolling interests
Total Liabilities and Stockholders’ Equity
Balance Sheet
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments, loans and long-term receivables*
Net properties, plants and equipment
Other assets
Total Assets
Liabilities and Stockholders’ Equity
Accounts payable
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
Retained earnings
Other common stockholders’ equity
Noncontrolling interests
Total Liabilities and Stockholders’ Equity
*Includes intercompany loans.
See Notes to Consolidated Financial Statements.
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Millions of Dollars
At December 31, 2019
3,439
2,670
2,088
2,111
168
352
10,828
44,969
3,552
765
60,114
2,670
4
79
508
408
3,669
6,670
322
-
1,329
7,514
19,504
21,898
18,712
-
60,114
1,428
-
5,646
1,462
184
267
8,987
47,062
4,367
642
61,058
5,098
12
85
638
587
6,420
7,151
415
-
1,340
9,277
24,603
18,511
17,944
-
61,058
-
-
2
-
-
-
2
11,662
-
253
11,917
21
13
-
-
35
69
2,129
-
-
-
826
3,024
2,164
6,729
-
11,917
1,649
358
3,881
-
858
1,906
8,652
15,612
38,717
2,210
65,191
3,084
91
951
155
1,518
5,799
2,197
5,030
5,438
452
9,271
28,187
10,481
26,454
69
65,191
At December 31, 2018
-
-
78
-
-
-
78
15,199
-
227
15,504
76
13
-
-
35
124
2,143
-
-
-
839
3,106
1,113
11,285
-
15,504
4,487
248
6,707
-
823
307
12,572
16,926
41,796
1,269
72,563
7,113
99
1,235
171
552
9,170
2,249
7,273
5,819
424
8,126
33,061
9,764
29,613
125
72,563
-
-
(2,575)
-
-
-
(2,575)
(97,413)
-
(805)
(100,793)
(2,575)
-
-
-
-
(2,575)
-
-
(804)
-
(17,534)
(20,913)
(27,985)
(51,895)
-
(100,793)
-
-
(8,392)
-
-
-
(8,392)
(99,465)
(465)
(798)
(109,120)
(8,392)
(9)
-
-
-
(8,401)
(478)
-
(798)
-
(17,775)
(27,452)
(22,890)
(58,778)
-
(109,120)
5,088
3,028
3,401
2,111
1,026
2,259
16,913
8,906
42,269
2,426
70,514
3,200
105
1,030
663
2,045
7,043
14,790
5,352
4,634
1,781
1,864
35,464
39,742
(4,761)
69
70,514
5,915
248
4,067
1,462
1,007
575
13,274
9,664
45,698
1,344
69,980
3,895
112
1,320
809
1,259
7,395
14,856
7,688
5,021
1,764
1,192
37,916
34,010
(2,071)
125
69,980
$
$
$
$
$
$
$
$
-
-
5
-
-
1
6
34,076
-
3
34,085
-
(3)
-
-
84
81
3,794
-
-
-
1,787
5,662
33,184
(4,761)
-
34,085
-
-
28
-
-
1
29
29,942
-
4
29,975
-
(3)
-
-
85
82
3,791
-
-
-
725
4,598
27,512
(2,135)
-
29,975
182
Statement of Cash Flows
ConocoPhillips
Company
Resources LLC
Millions of Dollars
Year Ended December 31, 2019
Burlington
ConocoPhillips
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
$
1,457
7,986
3,207
9,803
(11,349)
11,104
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net purchases of investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Intercompany cash management
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Used in Financing Activities
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
Net Change in Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, Cash Equivalents and Restricted Cash at End of Period
Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net sales of short-term investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Intercompany cash management
Other
Net Cash Provided by (Used in) Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Used in Financing Activities
$
$
-
-
2,374
-
-
-
1,060
-
3,434
-
-
105
(3,500)
(1,500)
4
(4,891)
-
-
-
-
(2,517)
37
7,047
(2,803)
(812)
141
(2,849)
(149)
(1,905)
-
(21)
-
-
(4,034)
-
(4,055)
(11)
2,015
1,428
3,443
-
-
769
-
-
-
1,402
-
2,171
-
-
-
-
(454)
(4,924)
(5,378)
-
-
-
-
(5,714)
(140)
1,055
(107)
-
147
387
41
(4,331)
812
(220)
-
-
(7,097)
(1,736)
(8,241)
(35)
(2,804)
4,723
1,919
1,595
-
(8,233)
-
812
(161)
-
-
(5,987)
(812)
161
(135)
-
11,585
6,537
17,336
-
-
-
-
(6,636)
(103)
3,012
(2,910)
-
127
-
(108)
(6,618)
-
(80)
(30)
(3,500)
(1,500)
(119)
(5,229)
(46)
(789)
6,151
5,362
Year Ended December 31, 2018*
860
4,019
838
14,132
(6,915)
12,934
-
-
3,457
-
-
589
(803)
-
3,243
-
-
254
(2,999)
(1,363)
5
(4,103)
-
-
-
-
(980)
(110)
666
-
(126)
3,432
3,504
151
6,537
10
(4,865)
-
-
(1,043)
(3,468)
(9,366)
4
1,194
234
1,428
(603)
-
1,926
-
(173)
212
(2,150)
-
(788)
-
(53)
-
-
-
-
(53)
-
(3)
3
-
(5,777)
42
705
1,620
(10)
129
(551)
3
(3,839)
299
(4,320)
-
-
(6,057)
(1,670)
(11,748)
(121)
(1,576)
6,299
4,723
610
-
(5,672)
-
309
(4,243)
-
-
(8,996)
(309)
4,243
(133)
-
7,100
5,010
15,911
-
-
-
-
(6,750)
(68)
1,082
1,620
-
119
-
154
(3,843)
-
(4,995)
121
(2,999)
(1,363)
(123)
(9,359)
(117)
(385)
6,536
6,151
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
Net Change in Cash, Cash Equivalents and Restricted Cash
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.
183
Statement of Cash Flows
ConocoPhillips
Company
ConocoPhillips
Millions of Dollars
Year Ended December 31, 2017
All Other
Subsidiaries
Resources LLC
Burlington
Consolidating
Adjustments
Total
Consolidated
$
71
1,183
2,971
5,904
(3,052)
7,077
-
-
7,765
-
-
658
1,151
-
9,574
-
(5,459)
115
(3,000)
(1,305)
4
(9,645)
-
-
-
-
(1,663)
194
11,146
-
(214)
1,527
101
(8)
11,083
20
(4,411)
-
-
(235)
(7,765)
(12,391)
1
(124)
358
234
(4,351)
-
12,178
-
(65)
389
(1,341)
-
6,810
-
-
-
-
-
(9,781)
(9,781)
(2)
(2)
5
3
(3,795)
(62)
12,796
(1,790)
(20)
2,196
89
44
9,458
279
(2,661)
-
-
(2,995)
(7,377)
(12,754)
233
2,841
3,247
6,088
5,218
-
(30,025)
-
299
(4,655)
-
-
(29,163)
(299)
4,655
(178)
-
3,230
24,807
32,215
-
-
-
-
(4,591)
132
13,860
(1,790)
-
115
-
36
7,762
-
(7,876)
(63)
(3,000)
(1,305)
(112)
(12,356)
232
2,715
3,610
6,325
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Proceeds from asset dispositions
Net purchases of short-term investments
Long-term advances/loans—related parties
Collection of advances/loans—related parties
Intercompany cash management
Other
Net Cash Provided by Investing Activities
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Used in Financing Activities
Effect of Exchange Rate Changes on Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents
Cash and cash equivalents at beginning of period
Cash and Cash Equivalents at End of Period
See Notes to Consolidated Financial Statements.
$
184
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures designed to ensure information required to be disclosed in
reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded,
processed, summarized and reported within the time periods specified in Securities and Exchange Commission
rules and forms, and that such information is accumulated and communicated to management, including our
principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required
disclosure. As of December 31, 2019, with the participation of our management, our Chairman and Chief
Executive Officer (principal executive officer) and our Executive Vice President and Chief Financial Officer
(principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of
ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that
evaluation, our Chairman and Chief Executive Officer and our Executive Vice President and Chief Financial
Officer concluded our disclosure controls and procedures were operating effectively as of December 31, 2019.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the
Act, in the period covered by this report that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 on page 76 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm
This report is included in Item 8 on page 80 and is incorporated herein by reference.
Item 9B. OTHER INFORMATION
None.
185
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report on page 29.
Code of Business Ethics and Conduct for Directors and Employees
We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our
principal executive officer, principal financial officer, principal accounting officer and persons performing
similar functions. We have posted a copy of our Code of Ethics on the “Corporate Governance” section of our
internet website at www.conocophillips.com (within the Investors>Corporate Governance section). Any
waivers of the Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments
to, or waivers from, the Code of Ethics that apply to our executive officers and directors will be posted on the
“Corporate Governance” section of our internet website.
All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our
2020 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2020, and
is incorporated herein by reference.*
Item 11. EXECUTIVE COMPENSATION
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2020
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2020, and is
incorporated herein by reference.*
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2020
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2020, and is
incorporated herein by reference.*
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2020
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2020, and is
incorporated herein by reference.*
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2020
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2020, and is
incorporated herein by reference.*
_________________________
*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing
in our 2020 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a
part of this report.
186
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PART IV
(a) 1. Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements,
which appears on page 75, are filed as part of this annual report.
2. Financial Statement Schedules
Schedule II—Valuation and Qualifying Accounts, appears below. All other schedules are omitted
because they are not required, not significant, not applicable or the information is shown in another
schedule, the financial statements or the notes to consolidated financial statements.
3. Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages 188 through 196, are filed as part
of this annual report.
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS (Consolidated)
ConocoPhillips
Millions of Dollars
Balance at Charged to
Expense
Other (a) Deductions
Balance at
December 31
48
-
(26)
January 1
5
7,376
25
3,040
Description
2019
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable $
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
2018
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable $
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
2017
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable $
Deferred tax asset valuation allowance
Included in other liabilities:
Restructuring accruals
1
(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.
4
1,254
23
2,067
2
560
5
675
-
19
-
(8)
70
53
80
65
(2)
(1)
-
(17) (b)
(176)
13
10,214
(24) (c)
23
(2) (b)
(273)
(73) (c)
(3) (b)
-
(93) (c)
25
3,040
48
4
1,254
53
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information related to our deferred
tax asset valuation allowance.
187
Exhibit
Number
2.1
2.2†‡
2.3†‡
3.1
3.2
3.3
CONOCOPHILLIPS
INDEX TO EXHIBITS
Description
Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
Purchase and Sale Agreement, dated March 29, 2017, by and among ConocoPhillips Company,
ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy Partnership,
ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership,
ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by reference to
Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed
by ConocoPhillips on May 4, 2017).
Asset Purchase and Sale Agreement Amending Agreement, dated as of May 16, 2017, by and
among ConocoPhillips Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada
Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC)
Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by
reference to Exhibit 2.2 to the Current Report of ConocoPhillips on Form 8-K filed on May 18,
2017; File No. 001-32395).
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008;
File No. 001-32395).
Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips
(incorporated by reference to Exhibit 3.2 to the Current Report of ConocoPhillips on Form 8-K filed
on August 30, 2002; File No. 000-49987).
Amended and Restated By-Laws of ConocoPhillips, as amended and restated as of October 9, 2015
(incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed
on October 13, 2015; File No. 001-32395).
ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total
amount of securities authorized does not exceed 10 percent of the total assets of ConocoPhillips and
its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of
Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon
request.
4.1*
Description of Securities of the Registrant.
10.1
10.2
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
188
Exhibit
Number
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Description
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended
December 31, 1999; File No. 001-00720).
Amendment and Restatement of ConocoPhillips Supplemental Executive Retirement Plan, dated
April 19, 2012 (incorporated by reference to Exhibit 10.14 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference
to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to
Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.10.1* Amended and Restated ConocoPhillips Key Employee Supplemental Retirement Plan, dated
January 1, 2020.
10.10.2 Eighth Amendment to Retirement Plans as amended and restated effective January 1, 2016
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended June 30, 2018; File No. 001-32395).
10.11.1* Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title I, dated
January 1, 2020.
10.11.2* Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title II, dated
January 1, 2020.
10.12
10.13
10.14
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
Amendment and Restatement of 1998 Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2002; File No. 000-49987).
Amendment and Restatement of 1998 Key Employee Stock Performance Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2002; File No. 000-49987).
189
Exhibit
Number
10.15
Description
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
10.16.1 Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of the
Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended
December 31, 1999; File No. 001-14521).
10.16.2 Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.16.3 Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998 (incorporated by
reference to Exhibit 10.17.3 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2015; File No. 001-32395).
10.16.4 First Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated May 3, 1999 (incorporated by reference to Exhibit 10.17.4 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.5 Second Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated January 15, 2002 (incorporated by reference to Exhibit 10.17.5 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
10.16.6 Third Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated October 5, 2006 (incorporated by reference to Exhibit 10.17.6 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
10.16.7 Fourth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 1, 2012 (incorporated by reference to Exhibit 10.17.7 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.8 Fifth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 20, 2015 (incorporated by reference to Exhibit 10.17.8 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.17.1 ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003;
File No. 000-49987).
10.17.2 First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program
(incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarterly period ended June 30, 2008; File No. 001-32395).
10.18
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2003; File No. 000-49987).
10.19.1* Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title I,
dated January 1, 2020 (incorporated by reference to Exhibit 10.12.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
190
Exhibit
Number
Description
10.19.2* Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title II,
dated January 1, 2020 (incorporated by reference to Exhibit 10.12.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.20
10.21
Amendment and Restatement of ConocoPhillips Key Employee Change in Control Severance Plan,
effective January 1, 2014 (incorporated by reference to Exhibit 10.21 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2013; File No. 001-32395).
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-
32395).
10.22.1
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual
Meeting of Shareholders; File No. 000-49987).
10.22.2 Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2008; File No. 001-32395).
10.22.3 Form of Performance Share Unit Award Agreement under the Performance Share Program under
the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2008; File No. 001-32395).
10.23
10.24
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7,
2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2007; File No. 001-32395).
2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2009 Annual
Meeting of Shareholders; File No. 001-32395).
10.25.1
2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2011 Annual
Meeting of Shareholders; File No. 001-32395).
10.25.2 Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
effective February 9, 2012 (incorporated by reference to Exhibit 10 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2012; File No. 001-32395).
10.25.3 Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated September 18, 2012
(incorporated by reference to Exhibit 10.26.5 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.4 Form of Performance Share Unit Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.6 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
191
Exhibit
Number
Description
10.25.5 Form of Performance Share Unit Agreement—Canada under the Restricted Stock Program under
the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.7 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.6 Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.8 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.7 Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 5, 2013 (incorporated by reference to Exhibit 10.26.9 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2012; File No. 001-32395).
10.25.8 Form of Make-Up Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated January 1, 2012 (incorporated by reference to Exhibit 10.1
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2013;
File No. 001-32395).
10.25.9 Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 18, 2014 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
10.25.10 Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.12 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.25.11 Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.25.12 Form of Performance Period IX Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.3 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-
32395).
10.25.13 Form of Performance Period IX Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.4 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.25.14 Form of Performance Period X Award Agreement, as part of the ConocoPhillips Performance Share
Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 18, 2014 (incorporated by reference to Exhibit 10.5 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
192
Exhibit
Number
Description
10.25.15 Form of Performance Period XIV Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.23 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
001-32395).
10.25.16 Form of Performance Period XIV Award Agreement—Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.24 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
001-32395).
10.25.17 Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated March 31, 2014 (incorporated by reference to Exhibit 10.11
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File
No. 001-32395).
10.25.18 Form of Performance Share Unit Award Terms and Conditions for Performance Period 18, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 13, 2018 (incorporated by reference
to Exhibit 10.26.24 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2017; File No. 001-32395).
10.25.19 Form of Performance Share Unit Award Terms and Conditions for Performance Period 18 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 13, 2018 (incorporated by reference to Exhibit 10.26.25 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No. 001-32395).
10.26.1
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K filed on May 14, 2014; File
No. 001-32395).
10.26.2 Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated September 3, 2015 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
2015; File No. 001-32395).
10.26.3 Form of Retention Award Terms and Conditions, as part of the Restricted Stock Unit Award,
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended March 31, 2015; File No. 001-32395).
10.26.4 Form of Non-Employee Director Restricted Stock Units Terms and Conditions, as part of the
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips, dated January 15,
2016 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of ConocoPhillips on Form
10-Q for the quarter ended March 31, 2016; File No. 001-32395).
10.26.5 Form of Non-Employee Director Restricted Stock Units Terms and Conditions – Canadian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.4 to the Quarterly
193
Exhibit
Number
Description
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-
32395).
10.26.6 Form of Non-Employee Director Restricted Stock Units Terms and Conditions – Norwegian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.5 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-
32395).
10.26.7 Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Stock Option
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 14, 2017 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.8 Form of Performance Share Unit Award Terms and Conditions for Performance Period 17, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 14, 2017 (incorporated by reference
to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended
March 31, 2017; File No. 001-32395).
10.26.9 Form of Performance Share Unit Award Terms and Conditions for Performance Period 17 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 14, 2017 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.10 Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 14, 2017 (incorporated by reference to Exhibit 10.4 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.11 Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Executive
Restricted Stock Unit Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 13, 2018 (incorporated by reference to Exhibit 10.27.12 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No.
001-32395).
10.26.12 Form of Key Employee Award Terms and Conditions for eligible employees on the Canada payroll,
as part of the ConocoPhillips Executive Restricted Stock Unit Program granted under the 2014
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 13, 2018
(incorporated by reference to Exhibit 10.27.13 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 001-32395).
10.26.13 Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 13, 2018 (incorporated by reference to Exhibit 10.27.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No. 001-32395).
10.26.14 Form of Retention Award Terms and Conditions, 2017 revision, as part of the Restricted Stock Unit
Award, granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.27.15 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 001-32395).
194
Exhibit
Number
Description
10.26.15 Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Unit Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 14, 2019.
10.27* Amended and Restated 409A Annex to Nonqualified Deferred Compensation Arrangements of
ConocoPhillips, dated January 1, 2020 (incorporated by reference to Exhibit 10.8 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
Amendment, Change of Sponsorship, and Restatement of Certain Nonqualified Deferred
Compensation Plans of ConocoPhillips, dated April 19, 2012 (incorporated by reference to Exhibit
10.10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012;
File No. 001-32395).
Amendment and Restatement of the Burlington Resources Inc. Management Supplemental Benefits
Plan, dated April 19, 2012 (incorporated by reference to Exhibit 10.9 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
Amendment and Restatement of Deferred Compensation Trust Agreement for Non-Employee
Directors of Phillips Petroleum Company, dated June 23, 1995 (incorporated by reference to Exhibit
10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016;
File No. 001-32395).
Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66,
dated April 26, 2012 (incorporated by reference to Exhibit 10.2 to the Current Report of
ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).
Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated
by reference to Exhibit 10.3 to the Current Report of ConocoPhillips on Form 8-K filed on May 1,
2012; File No. 001-32395).
Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 12, 2012
(incorporated by reference to Exhibit 10.4 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012
(incorporated by reference to Exhibit 10.5 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
ConocoPhillips Clawback Policy dated October 3, 2012 (incorporated by reference to Exhibit 10.3
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012;
File No. 001-32395).
Term Loan Agreement, between ConocoPhillips, as borrower, ConocoPhillips Company, as
guarantor, Toronto Dominion (Texas) LLC, as administrative agent and the banks party thereto,
with TD Securities (USA) LLC, as lead arranger and bookrunner, dated March 18, 2016
(incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K
filed on March 21, 2016; File No. 001-32395).
195
Exhibit
Number
10.38
10.40
Description
Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated December 28, 2018
(incorporated by reference to Exhibit 10.39 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2019; File No. 001-32395).
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated September 23, 2019 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
2019; File No. 001-32395).
21*
List of Subsidiaries of ConocoPhillips.
23.1*
Consent of Ernst & Young LLP.
23.2*
Consent of DeGolyer and MacNaughton.
31.1*
31.2*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934.
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934.
32*
Certifications pursuant to 18 U.S.C. Section 1350.
99* Report of DeGolyer and MacNaughton.
101.INS* Inline XBRL Instance Document.
101.SCH* Inline XBRL Schema Document.
101.CAL* Inline XBRL Calculation Linkbase Document.
101.DEF* Inline XBRL Definition Linkbase Document.
101.LAB* Inline XBRL Labels Linkbase Document.
101.PRE* Inline XBRL Presentation Linkbase Document.
104*
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
* Filed herewith.
† The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K. ConocoPhillips agrees to
furnish a copy of any schedule omitted from this exhibit to the SEC upon request.
‡ ConocoPhillips has previously been granted confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2
under the Securities Exchange Act of 1934, as amended.
196
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
February 18, 2020
CONOCOPHILLIPS
/s/ Ryan M. Lance
Ryan M. Lance
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of
February 18, 2020, on behalf of the registrant by the following officers in the capacity indicated and by a
majority of directors.
Signature
Title
/s/ Ryan M. Lance
Ryan M. Lance
/s/ Don E. Wallette, Jr.
Don E. Wallette, Jr.
Chairman of the Board of Directors
and Chief Executive Officer
(Principal executive officer)
Executive Vice President and
Chief Financial Officer
(Principal financial officer)
/s/ Catherine A. Brooks
Catherine A. Brooks
Vice President and Controller
(Principal accounting officer)
197
/s/ Charles E. Bunch
Charles E. Bunch
/s/ Caroline M. Devine
Caroline M. Devine
/s/ Gay Huey Evans
Gay Huey Evans
/s/ John V. Faraci
John V. Faraci
/s/ Jody Freeman
Jody Freeman
/s/ Jeffrey A. Joerres
Jeffrey A. Joerres
/s/ William H. McRaven
William H. McRaven
/s/ Sharmila Mulligan
Sharmila Mulligan
/s/ Arjun N. Murti
Arjun N. Murti
/s/ Robert A. Niblock
Robert A. Niblock
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
198
THIS PAGE INTENTIONALLY LEFT BLANK
THIS PAGE INTENTIONALLY LEFT BLANK
THIS PAGE INTENTIONALLY LEFT BLANK
THIS PAGE INTENTIONALLY LEFT BLANK
Non-GAAP Financial Measures
USE OF NON-GAAP FINANCIAL INFORMATION
This annual report includes non-GAAP terms to help facilitate comparisons of company operating performance across
periods and with peer companies. The company believes that the non-GAAP measures included, when viewed in
combination with the company’s results prepared in accordance with GAAP, provide a more complete understanding
of the factors and trends affecting the company’s business and performance. The company’s board of directors and
management also use these non-GAAP measures to analyze the company’s operating performance across periods
when overseeing and managing the company’s business. Reconciliations of any non-GAAP measures presented in the
annual report to the nearest corresponding GAAP measures are included both in the annual report and on our website at
www.conocophillips.com/nongaap.
CASH FROM OPERATIONS
Cash provided by operating activities, excluding the impact from operating working capital. The company believes
this measure is meaningful, as it provides insight into the cash flows generated by operating activities across periods by
excluding the timing effects associated with operating working capital changes. 2019 cash provided by operating activities
was $11.1 billion. Excluding operating working capital change of ($0.6) billion, cash from operations was $11.7 billion.
FREE CASH FLOW
Cash from operations in excess of capital expenditures and investments. 2019 cash from operations was $11.7 billion,
which exceeded capital expenditures and investments of $6.6 billion by $5 billion. The company believes this measure is
meaningful as it provides insight into the company’s ability to fund its capital expenditures and investments from its cash
from operations. Free cash flow is not a measure of cash available for discretionary expenditures, since the company has
certain non-discretionary obligations, such as debt service, that are not deducted from the measure. Cash from operations is
a non-GAAP term defined above.
RETURN ON CAPITAL EMPLOYED
Calculated as a ratio, the numerator of which is net income plus after-tax interest expense and excluding after-tax
interest income, and the denominator of which is average total equity plus average total debt adjusted for average cash,
cash equivalents, restricted cash and short-term investments. Net income is adjusted for non-operational or special item
impacts. The company believes this measure is meaningful, as it provides insight into the profitability and capital efficiency
of the average capital employed over the long term.
Reconciliation of Return on Capital Employed (ROCE)
$ Millions, Except as Indicated
Numerator
Net Income (Loss) Attributable to ConocoPhillips
Adjustment to exclude special items
Net income attributable to noncontrolling interests
After-tax interest expense
After-tax interest income
ROCE Earnings
Denominator
Average total equity(1)
Average total debt(2)
Less: Average total cash(3)
Average capital employed
ROCE (percent)
For the Year Ended
12/31/2019
7,189
(3,153)
68
637
(119)
4,622
33,713
14,930
(7,352)
41,291
11.2%
(1) Average total equity is the average of beginning and ending total equity by quarter.
(2) Average total debt is the average of beginning and ending long-term debt and short-term debt by quarter.
(3) Average total cash is the average of beginning and ending cash, cash equivalents, restricted cash and short-term investments by quarter.
Other Terms
CASH AND SHORT-TERM INVESTMENTS
Cash includes cash, cash equivalents and restricted cash. For year-end 2019 cash, cash equivalents and restricted cash was
$5.4 billion and short-term investments was $3 billion. Restricted cash was $0.3 billion.
COST OF SUPPLY
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, G&A and carbon
tax (if currently assessed). If no carbon tax exists for the asset, it is not included in this metric. All barrels of resources are
discounted at 10 percent.
RESOURCES
Based on the Petroleum Resources Management System, a system developed by industry that classifies recoverable
hydrocarbons into commercial and sub-commercial to reflect their status at the time of reporting. Proved, probable and
possible reserves are classified as commercial, while remaining resources are categorized as sub-commercial or contingent.
The company’s resource estimate includes volumes associated with both commercial and contingent categories. The SEC
permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. U.S.
investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC.
Dear Fellow Shareholders: I’m pleased to report that 2019 was another successful year for ConocoPhillips, capping off a three-year period during which we transformed our business model and significantly improved the underlying performance drivers across our entire business. In late 2016 we launched a “new-order” business model for the upstream energy sector that focused on a disciplined strategy framework, consistent execution, a strong balance sheet, free cash flow generation, compelling returns of and returns on capital, and a clear commitment to environmental, social and governance leadership. We believed then — and believe now — that this approach positions ConocoPhillips to deliver sustained value through our sector’s inevitable price cycles. Since that 2016 reset we’ve successfully executed this strategy, and our 2019 results built upon this multi-year track record.Our financial achievements during 2019 included generating cash from operations of $11.7 billion, with free cash flow of over $5 billion. We strengthened our balance sheet, ending the year with more than $8 billion in cash and short-term investments. We lowered our asset retirement obligations by almost 30 percent, largely through asset dispositions. Importantly, we achieved an 11 percent return on capital employed, which we consider our North Star.We delivered on our volume projections for the year, achieving 5 percent growth in underlying production, including 22 percent growth on a combined basis from the Lower 48 Big 3 unconventional fields — Eagle Ford, Bakken and Permian. The rest of our portfolio delivered strong base performance, and we progressed new projects and exploration opportunities across our regions.We improved our world-class asset portfolio through high-grading. We generated $3 billion of disposition proceeds, with another $2 billion of announced dispositions expected to close in early 2020. We also added low cost of supply resources to the portfolio, which allowed us to exit the year with resources of about 15 billion barrels of oil equivalent in our investment inventory with a cost of supply less than $40 per barrel. As for reserves, in 2019 we replaced 100 percent of our production and, excluding dispositions, replaced 117 percent of our production organically.It was an outstanding year for delivery of our disciplined, shareholder-friendly strategy. We returned 43 percent of cash from operations to our shareholders, which represented nearly all our free cash flow. We paid $1.5 billion in dividends, including a 38 percent increase in our quarterly dividend, and repurchased $3.5 billion of shares. In January 2020, our board of directors increased our existing share repurchase authorization by $10 billion to a total of $25 billion, demonstrating our commitment to a consistent long-term buyback program.But 2019, like the years before it, was not just about the numbers. We continued taking a leadership role in environmental, social and governance matters through target-setting, stakeholder engagement and alignment, disclosure and advocacy. We call this “performance with purpose,” and consider it imperative for today’s license to operate.As we turn the page and begin a new year and new decade, our industry is off to another volatile start. Volatility can be tough on companies not built for it. But ConocoPhillips is built for it, with clear resilience to lower prices, full upside to higher prices and a shareholder-friendly strategy framework that works throughout the business cycles. In November we laid out a powerful 10-year plan, reaffirming our commitment to the disciplined strategy we set for ourselves in 2016. We delivered on that strategy in 2017, 2018 and 2019, and we’re ready to deliver on it again in 2020. We’re focused on executing a plan that we believe is right for the future of our industry and right for our investors.In recognition of these achievements and goals for the future, our board of directors and leadership team express appreciation to employees for their focus and dedication, and we thank our shareholders for their continued trust. Ryan M. LanceChairman and Chief Executive OfficerFeb. 18, 2020LETTER TO SHAREHOLDERSBOARD OF DIRECTORS(As of Feb. 18, 2020)Charles E. Bunch Former Chairman and Chief Executive Officer, PPG Industries, Inc.Caroline Maury DevineFormer President and Managing Director of a Norwegian affiliate of ExxonMobilJohn V. Faraci Former Chairman and Chief Executive Officer, International Paper CompanyJody Freeman Archibald Cox Professor of Law, Harvard Law SchoolGay Huey Evans OBE Chairman, London Metal ExchangeJeffrey A. Joerres Former Executive Chairman and Chief Executive Officer, ManpowerGroup Inc.Ryan M. Lance Chairman and Chief Executive Officer, ConocoPhillipsRyan M. LanceChairman and Chief Executive OfficerMatt J. FoxExecutive Vice President and Chief Operating OfficerDon E. Wallette, Jr.Executive Vice President and Chief Financial OfficerWilliam L. Bullock, Jr.President, Asia Pacific and Middle EastEllen R. DeSanctisSenior Vice President, Corporate RelationsEXECUTIVE LEADERSHIP TEAM(As of Feb. 18, 2020)Admiral William H. McRavenRetired U.S. Navy Four-Star Admiral (SEAL) Sharmila MulliganChief Strategy Officer, AlteryxArjun N. Murti Senior Advisor, Warburg PincusRobert A. Niblock Former Chairman, President and Chief Executive Officer, Lowe’s Companies, Inc.Elected March 2, 2020David T. SeatonFormer Chairman and Chief Executive Officer, Fluor Corporation R.A. WalkerFormer Chairman and Chief Executive Officer, Anadarko Petroleum CorporationMichael D. HatfieldPresident, Alaska, Canada and EuropeAndrew D. LundquistSenior Vice President, Government AffairsDominic E. MacklonPresident, Lower 48Kelly B. RoseSenior Vice President, Legal, General Counsel and Corporate SecretaryCertain disclosures in this annual report may be considered “forward-looking” statements. These are made pursuant to “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The “Cautionary Statement” in the Management’s Discussion and Analysis in ConocoPhillips’ 2019 Form 10-K should be read in conjunction with such statements.“ConocoPhillips,” “the company,” “we,” “us” and “our” are used interchangeably in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries.Cautionary Note to U.S. Investors – The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. We use the terms “resource” and “resources” in this annual report, which the SEC’s guidelines prohibit us from including in filings with the SEC. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC. Copies are available from the SEC and on the ConocoPhillips website.EXPLORE CONOCOPHILLIPSSustainability ReportOur annual Sustainability Report provides details on priority reporting issues for the company, a letter from our CEO and key environmental, social and governance metrics. The report is updated in June and is available on our website at www.conocophillips.com/susdev.Managing Climate-Related Risks ReportOur Managing Climate-Related Risks Report includes a letter from our CEO and details on our governance framework, risk management approach, strategy, and key metrics and targets for climate-related issues. The report is available on our website at www.conocophillips.com/ climatechange.2019 Analyst & Investor MeetingDuring 2019 ConocoPhillips conducted an Analyst & Investor Meeting that presented an overview of the company’s 10-year strategic plan. A slide deck and transcript are available on our website at www.conocophillips.com/ investorpresentations.Fact SheetsThe ConocoPhillips Fact Sheets provide detailed operational updates for each of the company’s six segments. The Fact Sheets are updated annually and are available at www.conocophillips.com/factsheets. Curtis Island on Australia’s east coast is home to Australia Pacific LNG, which produces liquefied natural gas for the global market. Demand is rising worldwide for this abundant, affordable and clean-burning energy source.ConocoPhillips 2019 ANNUAL REPORT2019ANNUAL REPORT