ConocoPhillips has procedures
in place that minimize the
environmental risk and impact
of drilling and development.
Additionally, the company has
voluntarily set a long-term
target to reduce its greenhouse
gas emissions intensity by
5 to 15 percent by 2030.
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2 0 1 8
A N N U A L R E P O R T
LETTER TO SHAREHOLDERS
BOARD OF DIRECTORS
(As of Feb. 19, 2019)
Dear Fellow Shareholders:
The ConocoPhillips team delivered another exceptional year in 2018. Our operational
performance drove strong financial results and generated sector-leading total
shareholder returns (TSR) of 16 percent. We view this strong TSR performance as
an endorsement of the disciplined, returns-focused value proposition we launched
in late 2016.
At that time, we implemented a strategy that we believe remains the right one for
the E&P sector. Although our business is opportunity-rich, it’s also mature, capital-
intensive and cyclical. In embracing these realities, we’ve led the industry in setting
clear priorities for how we’ll allocate cash to generate superior returns through cycles.
Designing a value proposition is one thing; delivering on it is another. Over the past two years, we’ve taken
numerous actions to improve the underlying quality of our business. We’ve significantly lowered our sustaining
price and strengthened our balance sheet. We’ve grown our resource base with a cost of supply less than $40 per
barrel West Texas Intermediate. We’ve delivered competitive per-share growth, not chased absolute growth.
We’ve returned a distinctive portion of cash flows to shareholders, kept costs in check and generated one of our
industry’s most competitive financial returns. Our 2018 results demonstrate that our value proposition is working.
During the year ConocoPhillips achieved:
• Financial returns that surpassed the returns from just a few years ago when Brent prices averaged more than
50 percent higher;
• Cash from operations that exceeded capital spending by $5.5 billion;
• Higher-than-targeted production growth on a per debt-adjusted share basis;
• Debt reduction of $4.7 billion, thus achieving our $15 billion total debt target 18 months early;
• 35 percent payout of cash from operations to shareholders via our dividend and $3 billion of share buybacks;
• Portfolio enhancements through exploration success and acquisitions in Alaska, acreage additions in the Lower 48
and Canada, and proceeds from non-core asset dispositions of $1.1 billion;
• 147 percent total reserve replacement, and 109 percent organic reserve replacement excluding asset transactions;
• And year-end reserves of 5.3 billion barrels of oil equivalent.
Importantly, we delivered these milestones safely and sustainably, while engaging with our many stakeholders. 2018
was a gratifying year and we’re excited about our opportunities in 2019. We’ll maintain our disciplined approach
with a $6.1 billion capital budget, a focus on per-share growth, an increasing dividend, and $3 billion in planned
share buybacks for the third straight year. Operationally, we’ll conduct exploration, appraisal and development in
the Lower 48, Alaska, Canada and Europe, with major project decisions pending in China, Australia and elsewhere.
We believe that our 2019 operating plan reflects what you’ve come to expect from us. It’s consistent with our
priorities, focused on long-term value creation and underpinned by our commitment to strong execution. This is
our formula for delivering superior returns to shareholders through the cycles, and for many years to come. Our
formula works and we’re sticking to it.
We appreciate our employees and shareholders for their ongoing support of ConocoPhillips.
Ryan M. Lance
Chairman and Chief Executive Officer
Feb. 19, 2019
Charles E. Bunch
Former Chairman and Chief Executive
Officer, PPG Industries, Inc.
Ryan M. Lance
Chairman and Chief Executive Officer,
ConocoPhillips
Admiral William H. McRaven
Retired U.S. Navy Four-Star Admiral (SEAL)
Sharmila Mulligan
Founder and Chief Executive Officer,
ClearStory Data Inc.
Arjun N. Murti
Senior Advisor, Warburg Pincus
Robert A. Niblock
Former Chairman, President and Chief
Executive Officer, Lowe’s Companies, Inc.
Harald J. Norvik
Former Chairman, President and
Chief Executive Officer, Statoil
Caroline Maury Devine
Former President and Managing Director
of a Norwegian affiliate of ExxonMobil
John V. Faraci
Former Chairman and Chief Executive
Officer, International Paper Company
Jody Freeman
Archibald Cox Professor of Law,
Harvard Law School
Gay Huey Evans OBE
Member of Her Majesty’s Treasury Board,
Sub-Committee and Nominations
Committee
Jeffrey A. Joerres
Former Executive Chairman and Chief
Executive Officer, ManpowerGroup Inc.
EXECUTIVE LEADERSHIP TEAM
(As of Feb. 19, 2019)
Ryan M. Lance
Chairman and Chief Executive Officer
Michael D. Hatfield
President, Alaska, Canada and Europe
Matt J. Fox
Executive Vice President and
Chief Operating Officer
Don E. Wallette, Jr.
Executive Vice President and
Chief Financial Officer
William L. Bullock, Jr.
President, Asia Pacific & Middle East
Ellen R. DeSanctis
Senior Vice President, Corporate Relations
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
Certain 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’ 2018 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.
Use of Non-GAAP Financial Information – This annual report includes the non-GAAP term “cash from operations” to help facilitate
comparisons of company operating performance across periods and with peer companies. Cash from operations is defined as cash provided
by operating activities excluding the impact of operating working capital. 2018 cash provided by operating activities is $12.9 billion. Excluding
operating working capital of $0.6 billion, cash from operations is $12.3 billion.
EXPLORE
CONOCOPHILLIPS
Fact Sheets
The 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.
Sustainability Report
Our 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 Report
Our 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.
2018
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, 2018
[ ] 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
(State or other jurisdiction of
incorporation or organization)
01-0562944
(I.R.S. Employer
Identification No.)
925 N. Eldridge Parkway
Houston, TX 77079
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-293-1000
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $.01 Par Value
7% Debentures due 2029
Title of each class
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
Act.
[ ] Yes [x] No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [x] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be
submitted pursuant to Rule 405 of Regulation S-T 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
(cid:75)(cid:72)(cid:85)(cid:72)(cid:76)(cid:81)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:76)(cid:79)(cid:79)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:69)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:68)(cid:76)(cid:81)(cid:72)(cid:71)(cid:15)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:72)(cid:86)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:78)(cid:81)(cid:82)(cid:90)(cid:79)(cid:72)(cid:71)(cid:74)(cid:72)(cid:15)(cid:3)(cid:76)(cid:81)(cid:3)(cid:71)(cid:72)(cid:73)(cid:76)(cid:81)(cid:76)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:91)(cid:92)(cid:3)(cid:82)(cid:85)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a
(cid:86)(cid:80)(cid:68)(cid:79)(cid:79)(cid:72)(cid:85)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:15)(cid:3)(cid:82)(cid:85)(cid:3)(cid:68)(cid:81)(cid:3)(cid:72)(cid:80)(cid:72)(cid:85)(cid:74)(cid:76)(cid:81)(cid:74)(cid:3)(cid:74)(cid:85)(cid:82)(cid:90)(cid:87)(cid:75)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:17)(cid:3)(cid:3)(cid:54)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:71)(cid:72)(cid:73)(cid:76)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:179)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:3)(cid:68)(cid:70)(cid:70)(cid:72)(cid:79)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:76)(cid:79)(cid:72)(cid:85)(cid:15)(cid:180)(cid:3)
(cid:179)(cid:68)(cid:70)(cid:70)(cid:72)(cid:79)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:76)(cid:79)(cid:72)(cid:85)(cid:15)(cid:180)(cid:3)(cid:179)(cid:86)(cid:80)(cid:68)(cid:79)(cid:79)(cid:72)(cid:85)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:179)(cid:72)(cid:80)(cid:72)(cid:85)(cid:74)(cid:76)(cid:81)(cid:74)(cid:3)(cid:74)(cid:85)(cid:82)(cid:90)(cid:87)(cid:75)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:180)(cid:3)(cid:76)(cid:81)(cid:3)(cid:53)(cid:88)(cid:79)(cid:72)(cid:3)(cid:20)(cid:21)(cid:69)-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 29, 2018, the last
(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:71)(cid:68)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:80)(cid:82)(cid:86)(cid:87)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:81)(cid:87)(cid:79)(cid:92)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:79)(cid:72)(cid:87)(cid:72)(cid:71)(cid:3)(cid:86)(cid:72)(cid:70)(cid:82)(cid:81)(cid:71)(cid:3)(cid:73)(cid:76)(cid:86)(cid:70)(cid:68)(cid:79)(cid:3)(cid:84)(cid:88)(cid:68)(cid:85)(cid:87)(cid:72)(cid:85)(cid:15)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:79)(cid:82)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:71)(cid:68)(cid:87)(cid:72)(cid:3)
of $69.62, was $80.9 billion.
The registrant had 1,134,404,094 shares of common stock outstanding at January 31, 2019.
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 14, 2019 (Part III)
Documents incorporated by reference:
TABLE OF CONTENTS
Item
Page
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 .....................................................................................................
Executive Officers of the Registrant ...................................................................................
PART II
5. (cid:48)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:53)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)(cid:15)(cid:3)(cid:53)(cid:72)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:3)(cid:48)(cid:68)(cid:87)(cid:87)(cid:72)(cid:85)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)
Issuer Purchases of Equity Securities ............................................................................
6. Selected Financial Data ......................................................................................................
7. (cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)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
1
1
1
3
5
8
9
12
16
18
19
20
28
28
28
29
31
33
34
78
81
187
187
187
188
188
188
188
188
15. Exhibits, Financial Statement Schedules ............................................................................
Signatures ...........................................................................................................................
189
200
PART I
(cid:56)(cid:81)(cid:79)(cid:72)(cid:86)(cid:86)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:90)(cid:76)(cid:86)(cid:72)(cid:3)(cid:76)(cid:81)(cid:71)(cid:76)(cid:70)(cid:68)(cid:87)(cid:72)(cid:71)(cid:15)(cid:3)(cid:179)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:15)(cid:180)(cid:3)(cid:179)(cid:90)(cid:72)(cid:15)(cid:180)(cid:3)(cid:179)(cid:82)(cid:88)(cid:85)(cid:15)(cid:180)(cid:3)(cid:179)(cid:88)(cid:86)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:179)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:180)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:88)(cid:86)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)
refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2(cid:178)Business and
Properties, contain forward-looking statements including, without limitation, statements relating to our plans,
(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:72)(cid:74)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)(cid:82)(cid:69)(cid:77)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:86)(cid:15)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:70)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:80)(cid:68)(cid:71)(cid:72)(cid:3)(cid:83)(cid:88)(cid:85)(cid:86)(cid:88)(cid:68)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:86)(cid:68)(cid:73)(cid:72)(cid:3)(cid:75)(cid:68)(cid:85)(cid:69)(cid:82)(cid:85)(cid:180)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)
Private Securities Litigation Reform Act of 1995. The words (cid:179)(cid:68)(cid:81)(cid:87)(cid:76)(cid:70)(cid:76)(cid:83)(cid:68)(cid:87)(cid:72)(cid:15)(cid:180) (cid:179)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:15)(cid:180) (cid:179)(cid:69)(cid:72)(cid:79)(cid:76)(cid:72)(cid:89)(cid:72)(cid:15)(cid:180) (cid:179)(cid:69)(cid:88)(cid:71)(cid:74)(cid:72)(cid:87)(cid:15)(cid:180)
(cid:179)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:15)(cid:180) (cid:179)(cid:70)(cid:82)(cid:88)(cid:79)(cid:71)(cid:15)(cid:180) (cid:179)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:71)(cid:15)(cid:180) (cid:179)(cid:80)(cid:68)(cid:92)(cid:15)(cid:180) (cid:179)(cid:83)(cid:79)(cid:68)(cid:81)(cid:15)(cid:180) (cid:179)(cid:83)(cid:82)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:68)(cid:79)(cid:15)(cid:180) (cid:179)(cid:83)(cid:85)(cid:72)(cid:71)(cid:76)(cid:70)(cid:87)(cid:15)(cid:180) (cid:179)(cid:86)(cid:72)(cid:72)(cid:78)(cid:15)(cid:180) (cid:179)(cid:86)(cid:75)(cid:82)(cid:88)(cid:79)(cid:71)(cid:15)(cid:180) (cid:179)(cid:90)(cid:76)(cid:79)(cid:79)(cid:15)(cid:180) (cid:179)(cid:90)(cid:82)(cid:88)(cid:79)(cid:71)(cid:15)(cid:180)
(cid:179)(cid:72)(cid:91)(cid:83)(cid:72)(cid:70)(cid:87)(cid:15)(cid:180) (cid:179)(cid:82)(cid:69)(cid:77)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:15)(cid:180) (cid:179)(cid:83)(cid:85)(cid:82)(cid:77)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:180) (cid:179)(cid:73)(cid:82)(cid:85)(cid:72)(cid:70)(cid:68)(cid:86)(cid:87)(cid:15)(cid:180) (cid:179)(cid:74)(cid:82)(cid:68)(cid:79)(cid:15)(cid:180) (cid:179)(cid:74)(cid:88)(cid:76)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:15)(cid:180) (cid:179)(cid:82)(cid:88)(cid:87)(cid:79)(cid:82)(cid:82)(cid:78)(cid:15)(cid:180) (cid:179)(cid:72)(cid:73)(cid:73)(cid:82)(cid:85)(cid:87)(cid:15)(cid:180) (cid:179)(cid:87)(cid:68)(cid:85)(cid:74)(cid:72)(cid:87)(cid:180) 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 (cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86) disclosures
under the headings (cid:179)(cid:53)(cid:76)(cid:86)(cid:78) (cid:41)(cid:68)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:180) beginning on page 20 and (cid:179)(cid:38)(cid:36)(cid:56)(cid:55)(cid:44)(cid:50)(cid:49)(cid:36)(cid:53)(cid:60)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:3)(cid:41)(cid:50)(cid:53)(cid:3)(cid:55)(cid:43)(cid:40)(cid:3)
(cid:51)(cid:56)(cid:53)(cid:51)(cid:50)(cid:54)(cid:40)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:55)(cid:43)(cid:40)(cid:3)(cid:181)(cid:54)(cid:36)(cid:41)(cid:40)(cid:3)(cid:43)(cid:36)(cid:53)(cid:37)(cid:50)(cid:53)(cid:182)(cid:3)(cid:51)(cid:53)(cid:50)(cid:57)(cid:44)(cid:54)(cid:44)(cid:50)(cid:49)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:55)(cid:43)(cid:40)(cid:3)(cid:51)(cid:53)(cid:44)(cid:57)(cid:36)(cid:55)(cid:40)(cid:3)(cid:54)(cid:40)(cid:38)(cid:56)(cid:53)(cid:44)(cid:55)(cid:44)(cid:40)(cid:54)(cid:3)(cid:47)(cid:44)(cid:55)(cid:44)(cid:42)(cid:36)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)
(cid:53)(cid:40)(cid:41)(cid:50)(cid:53)(cid:48)(cid:3)(cid:36)(cid:38)(cid:55)(cid:3)(cid:50)(cid:41)(cid:3)(cid:20)(cid:28)(cid:28)(cid:24)(cid:15)(cid:180)(cid:3)(cid:69)(cid:72)(cid:74)(cid:76)(cid:81)ning on page 76.
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:90)(cid:82)(cid:85)(cid:79)(cid:71)(cid:182)(cid:86)(cid:3)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:87)(cid:3)(cid:76)(cid:81)(cid:71)(cid:72)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:72)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:11)(cid:40)(cid:9)(cid:51)(cid:12)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:15)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)
proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have
operations and activities in 16 countries. Our diverse, low cost of supply portfolio includes resource-rich
unconventional plays in North America; lower-risk conventional assets in North America, Europe, Asia and
Australia; liquefied natural gas (LNG) developments; oil sands assets in Canada; and an inventory of global
conventional and unconventional exploration prospects. At December 31, 2018, we employed approximately
10,800 people worldwide and had total assets of $70 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.
In April 2012, ConocoPhillips completed the separation of the downstream business into an independent,
publicly traded energy company, Phillips 66.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 25(cid:178)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 natural gas liquids on
a worldwide basis. At December 31, 2018, our operations were producing in the United States, Norway, the
United Kingdom, Canada, Australia, Timor-Leste, Indonesia, Malaysia, Libya, China and Qatar.
The information listed below appears (cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:68)(cid:86)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:79)(cid:82)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:73)(cid:82)(cid:79)(cid:79)(cid:82)(cid:90)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)
Consolidated Financial Statements and is incorporated herein by reference:
(cid:120) Proved worldwide crude oil, natural gas liquids, natural gas and bitumen reserves.
(cid:120) Net production of crude oil, natural gas liquids, natural gas and bitumen.
(cid:120) Average sales prices of crude oil, natural gas liquids, natural gas and bitumen.
1
(cid:120) Average production costs per barrel of oil equivalent (BOE).
(cid:120) Net wells completed, wells in progress and productive wells.
(cid:120) Developed and undeveloped acreage.
(cid:55)(cid:75)(cid:72)(cid:3)(cid:73)(cid:82)(cid:79)(cid:79)(cid:82)(cid:90)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:86)(cid:88)(cid:80)(cid:80)(cid:68)(cid:85)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:68)(cid:86)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)
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 thousand
cubic feet (MCF) of natural gas converts to one BOE. (cid:54)(cid:72)(cid:72)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)
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
Equity affiliates
Total Bitumen
Total consolidated operations
Total equity affiliates
Total company
Millions of Barrels of Oil Equivalent
2018
2017
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
2016
2,047
88
2,135
457
47
504
1,807
730
2,537
159
1,089
1,248
4,470
1,954
6,424
Total production, including Libya, of 1,283 thousand barrels of oil equivalent per day (MBOED) decreased
7 percent in 2018 compared with 2017. The decrease in total average production primarily resulted from
noncore asset dispositions, including the dispositions 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, and our
interest in the San Juan Basin in the Lower 48 in 2017; normal field decline; and higher unplanned downtime,
including a third-party pipeline outage in Malaysia in 2018. The decrease in production was partly offset by
growth from the Big 3 Unconventionals(cid:178)Eagle Ford, Bakken and Delaware, development programs primarily
in Europe and Alaska, and rampup of major projects in Asia Pacific.
Production excluding Libya was 1,242 MBOED in 2018 compared with 1,356 MBOED in 2017. The volume
from closed dispositions was approximately 200 MBOED in 2017 and 15 MBOED in 2018. The volume from
acquisitions was less than 10 MBOED in 2018. Our underlying production, which excludes the full-year
impact of acquisitions, dispositions, and Libya, increased over 5 percent in 2018 compared with 2017.
2
Our worldwide annual average realized price was $53.88 per BOE in 2018, an increase of 37 percent compared
with $39.19 per BOE in 2017, reflecting stronger marker prices as well as a shift in our portfolio toward a
higher mix of crude oil and less of bitumen and natural gas. Our worldwide annual average crude oil price
increased 31 percent in 2018, from $51.96 per barrel in 2017 to $68.13 per barrel in 2018. Additionally, our
worldwide annual average natural gas liquids prices increased 21 percent, from $25.22 per barrel in 2017 to
$30.48 per barrel in 2018. Our worldwide annual average natural gas price increased 39 percent, from
$4.07 per MCF in 2017 to $5.65 per MCF in 2018. Average annual bitumen prices decreased 2 percent, from
$22.66 per barrel in 2017 to $22.29 per barrel in 2018.
ALASKA
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and natural
gas liquids. We are the largest crude oil producer in Alaska and have major ownership interests in two of
(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:3)(cid:36)(cid:80)(cid:72)(cid:85)(cid:76)(cid:70)(cid:68)(cid:182)(cid:86)(cid:3)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:87)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:73)(cid:76)(cid:72)(cid:79)(cid:71)(cid:86)(cid:3)(cid:79)(cid:82)(cid:70)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:36)(cid:79)(cid:68)(cid:86)(cid:78)(cid:68)(cid:182)(cid:86)(cid:3)(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:3)(cid:54)(cid:79)(cid:82)(cid:83)(cid:72)(cid:29)(cid:3)(cid:51)(cid:85)(cid:88)(cid:71)(cid:75)(cid:82)(cid:72)(cid:3)(cid:37)(cid:68)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:46)(cid:88)(cid:83)(cid:68)(cid:85)(cid:88)(cid:78)(cid:17)(cid:3)(cid:3)(cid:58)(cid:72) also have
a 100 percent interest in the Alpine Field, located on the Western North Slope. Additionally, we are one of
(cid:36)(cid:79)(cid:68)(cid:86)(cid:78)(cid:68)(cid:182)(cid:86)(cid:3)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:87)(cid:3)(cid:82)(cid:90)(cid:81)(cid:72)(cid:85)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:15)(cid:3)(cid:73)(cid:72)(cid:71)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:73)(cid:72)(cid:72)(cid:3)(cid:72)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:79)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:83)(cid:83)(cid:85)(cid:82)(cid:91)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:79)(cid:92)(cid:3)(cid:20)(cid:17)(cid:21)(cid:24)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)
undeveloped acres at year-end 2018. Alaska operations contributed 23 percent of our worldwide liquids
production and less than 1 percent of our natural gas production.
Interest
Operator
MBD *
MMCFD **
Liquids
2018
Natural Gas
Average Daily Net Production
Greater Prudhoe Area
Greater Kuparuk Area***
Western North Slope***
Total Alaska
*Thousands of barrels per day.
**Millions of cubic feet per day.
*** Interest at December 31, 2018. See "Acquisitions" below for additional information.
BP
ConocoPhillips
ConocoPhillips
91.4-94.7
100.0
36.1 %
85
56
44
185
5
1
-
6
Total
MBOED
86
56
44
186
Greater Prudhoe Area
The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point
(cid:48)(cid:70)(cid:44)(cid:81)(cid:87)(cid:92)(cid:85)(cid:72)(cid:3)(cid:36)(cid:85)(cid:72)(cid:68)(cid:3)(cid:73)(cid:76)(cid:72)(cid:79)(cid:71)(cid:86)(cid:17)(cid:3)(cid:3)(cid:51)(cid:85)(cid:88)(cid:71)(cid:75)(cid:82)(cid:72)(cid:3)(cid:37)(cid:68)(cid:92)(cid:15)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:87)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:73)(cid:76)(cid:72)(cid:79)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:36)(cid:79)(cid:68)(cid:86)(cid:78)(cid:68)(cid:182)(cid:86)(cid:3)(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:3)(cid:54)(cid:79)(cid:82)(cid:83)(cid:72)(cid:15)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:76)(cid:87)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:3)
waterflood and enhanced oil recovery operation, as well as a gas plant which processes natural gas to recover
(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:79)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:86)(cid:3)(cid:69)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)(cid:3)(cid:85)(cid:72)(cid:76)(cid:81)(cid:77)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:82)(cid:76)(cid:85)(cid:17)(cid:3)(cid:3)(cid:51)(cid:85)(cid:88)(cid:71)(cid:75)(cid:82)(cid:72)(cid:3)(cid:37)(cid:68)(cid:92)(cid:182)(cid:86)(cid:3)(cid:86)(cid:68)(cid:87)(cid:72)(cid:79)(cid:79)(cid:76)(cid:87)(cid:72)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:36)(cid:88)(cid:85)(cid:82)(cid:85)(cid:68)(cid:15)(cid:3)(cid:37)(cid:82)(cid:85)(cid:72)(cid:68)(cid:79)(cid:76)(cid:86)(cid:15)(cid:3)(cid:51)(cid:82)(cid:79)(cid:68)(cid:85)(cid:76)(cid:86)(cid:15)(cid:3)
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.
We completed a transaction in the fourth quarter of 2018 which increased our interest in the Greater Kuparuk
Area by 39.2 percent. Further discussion of the (cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:68)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:70)(cid:84)(cid:88)(cid:76)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:69)(cid:72)(cid:79)(cid:82)(cid:90)(cid:17)(cid:3)(cid:3)
3
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 2018, 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, which is currently planned to have 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 we expect first oil from GMT-2 in 2021.
We completed a transaction in the second quarter of 2018 to increase our interest in the Western North Slope
from 78 percent to 100 percent. (cid:41)(cid:88)(cid:85)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:68)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:70)(cid:84)(cid:88)(cid:76)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
below.
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 front-end engineering and design
(pre-FEED) technical work for a potential LNG project which would liquefy and export natural gas from
(cid:36)(cid:79)(cid:68)(cid:86)(cid:78)(cid:68)(cid:182)(cid:86) 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 progressing the project on its own and signed several Memorandums
of Understanding with various potential LNG buyers in Asia. AGDC has also signed a Joint Development
Agreement with Sinopec, CIC Capital and Bank of China, which was recently extended to June 30, 2019. In
early January 2019, recently elected Governor Dunleavy appointed new members to (cid:36)(cid:42)(cid:39)(cid:38)(cid:182)(cid:86) board of
directors who replaced (cid:36)(cid:42)(cid:39)(cid:38)(cid:182)(cid:86) president with an interim president. The Dunleavy administration has
indicated they are interested in participation in the project by ConocoPhillips, ExxonMobil and BP. We
remain willing to make our equity gas available for sale to the project at mutually agreed, commercially
reasonable terms.
Exploration
Appraisal of the Willow Discovery, located in the northeast portion of the National Petroleum Reserve-Alaska,
continued throughout 2018 with three appraisal wells. Additionally, the West Willow-1 exploration well,
drilled in 2018, resulted in an oil discovery. In 2019, we will continue appraisal of the Willow and West
Willow discoveries.
The Putu 2/2A and Stony Hill 1 wells were drilled in 2018 on state and federal leases, resulting in oil
discoveries. In late 2018, we commenced appraisal of the Putu Discovery with a long reach well from existing
Alpine CD4 infrastructure.
The Cairn 2S-315 Well was drilled in late 2018 from the 2S drill site on state leases in the Kuparuk River Unit.
A flow test will commence in the first quarter of 2019.
A 3-D seismic survey was completed in 2018 over a 250-mile area on state lands. We are currently processing
this data.
We were successful in the federal lease sale on the North Slope in the fourth quarter of 2018, where we were
the high bidder on five tracts for a total of approximately 48,000 net acres.
Acquisitions
During the second quarter of 2018, we obtained regulatory approvals and completed a transaction we entered
into with Anadarko Petroleum Corporation to acquire its 22 percent nonoperated interest in the Western North
Slope of Alaska, as well as its interest in the Alpine Transportation Pipeline. In 2018, our Alaska segment net
production included 7 MBOED associated with the additional interest acquired.
4
During the fourth quarter of 2018, we completed a transaction with BP to acquire their 39.2 percent
nonoperated interest in the Greater Kuparuk Area, including their 38 percent interest in the Kuparuk
Transportation Company in Alaska (Kuparuk Assets), and to sell a ConocoPhillips subsidiary to BP, which
held 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the United Kingdom. In 2018,
our Alaska segment net production included 1 MBOED associated with the additional interest acquired in the
Greater Kuparuk Area.
See Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes to
Consolidated Financial Statements, for additional information.
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 United States.
LOWER 48
The Lower 48 segment consists of operations located in the contiguous United States and the Gulf of Mexico.
The Lower 48 business is organized within two regions covering the Gulf Coast and Great Plains. As a result
of tight oil opportunities, we have directed our investments toward certain shorter cycle time, low cost of
supply plays. We disposed of several noncore assets within the Lower 48 in 2018, including our interests in
the Barnett and certain conventional assets in the Permian Basin. In 2017, we disposed of our interest in the
San Juan Basin. We hold 10.3 million net onshore and offshore acres in the Lower 48. In 2018, the Lower 48
contributed 36 percent of our worldwide liquids production and 21 percent of our natural gas production.
Interest
Operator
Liquids
MBD
2018
Natural Gas
MMCFD
Total
MBOED
Average Daily Net Production
Eagle Ford
Gulf of Mexico
Gulf Coast(cid:178)Other
Total Gulf Coast
Bakken
Permian
Anadarko Basin
Wyoming/Uinta
Barnett
Niobrara
Total Great Plains
Total U.S. Lower 48
*See "Dispositions" below for additional information.
Various %
Various
Various
Various
Various
Various
Various
*
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
151
12
3
166
72
46
4
-
3
7
132
298
212
9
8
229
72
126
59
78
25
7
367
596
186
14
4
204
84
66
14
13
8
8
193
397
5
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 1.6 million net acres in the following areas:
(cid:120) 620,000 net acres in the Bakken, located in North Dakota and eastern Montana.
(cid:120) 225,000 net acres in central Louisiana.
(cid:120) 200,000 net acres in the Eagle Ford, located in South Texas.
(cid:120) 145,000 net acres in the Permian, located in West Texas and southeastern New Mexico.
(cid:120) 98,000 net acres in the Niobrara, located in northeastern Colorado.
(cid:120) 340,000 net acres in other areas with unconventional potential.
The majority of our 2018 onshore production originated from the Big 3(cid:178)Eagle Ford, Bakken and the
Delaware in the Permian Basin. Onshore activities in 2018 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 2018 included the following:
(cid:120) Eagle Ford(cid:178)The Eagle Ford continued full-field development in 2018. We operated seven rigs on
average in 2018, resulting in 166 operated wells drilled and 149 operated wells brought online.
Production increased 40 percent in 2018 compared with 2017, averaging 186 MBOED and
133 MBOED, respectively.
(cid:120) Bakken(cid:178)We operated an average of three rigs during the year in the Bakken. We continued our pad
drilling with 51 operated wells drilled during the year and 85 operated wells brought online.
Production increased 29 percent in 2018 compared with 2017, averaging 84 MBOED and
65 MBOED, respectively.
(cid:120) Permian Basin(cid:178)The Permian Basin is an area where we are leveraging our conventional legacy
position by utilizing new technology to improve the ultimate recovery and value from these fields.
We hold approximately 800,000 net acres in the Permian, which includes 145,000 net unconventional
acres. The Permian Basin produced 66 MBOED in 2018, increasing 6 percent compared to 2017,
including 28 MBOED of unconventional production from the Delaware. We disposed of several
noncore conventional assets throughout the year.
Dispositions
We completed the sale of our interests in the Barnett in the fourth quarter of 2018. Combined with the sale of
several noncore conventional assets in the Permian Basin, production from the assets sold was 10 MBOED,
approximately 3 percent of total Lower 48 production in 2018. For additional information on our asset
dispositions, see Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions, in the Notes
to Consolidated Financial Statements.
Gulf of Mexico
At year-end 2018, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one
operated field and three fields operated by co-venturers, totaling approximately 68,000 net acres, including:
(cid:120) 75 percent operated working interest in the Magnolia Field in Garden Banks Blocks 783 and 784.
(cid:120) 15.9 percent nonoperated working interest in the unitized Ursa Field located in the Mississippi Canyon
Area.
(cid:120) 15.9 percent nonoperated working interest in the Princess Field, a northern subsalt extension of the
Ursa Field.
(cid:120) 12.4 percent nonoperated working interest in the unitized K2 Field, comprised of seven blocks in the
Green Canyon Area.
6
Exploration
(cid:120) Conventional Exploration
In December 2017, we elected to withdraw from our Shenandoah leases. The withdrawal was
effective February 17, 2018, substantially completing our exit from deepwater Gulf of Mexico.
(cid:120) Unconventional Exploration
Our onshore focus areas include the Niobrara in the Denver-Julesburg Basin, the Delaware in the
Permian Basin, as well as several emerging plays such as the Louisiana Austin Chalk. We began
acquiring early life-cycle acreage in the Austin Chalk in the fourth quarter of 2017, and currently hold
approximately 225,000 net acres. We spud our first Austin Chalk well in late 2018 and plan to drill
additional wells in 2019.
Facilities
Golden Pass LNG Terminal
We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass
Pipeline, with a combined net book value of approximately $235 million at December 31, 2018. It is located
adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal became
commercially operational in May 2011. We hold terminal and pipeline capacity for the receipt, storage and
regasification of the LNG purchased from Qatar Liquefied Gas Company Limited (3) (QG3) and the
transportation of regasified LNG to interconnect with major interstate natural gas pipelines. Utilization of the
terminal has been and is expected to be limited, as market conditions currently favor the flow of LNG to
European and Asian markets. In January 2019, we entered into agreements to sell our 12.4 percent ownership
interests in Golden Pass LNG Terminal and the affiliated Golden Pass Pipeline. We have also entered into
agreements to amend our contractual obligations for remaining use of the facilities. Completion of the sale is
subject to regulatory approval.
Other
(cid:120) Lost Cabin Gas Plant(cid:178)We operate and own a 46 percent interest in the Lost Cabin Gas Plant, a
246 million cubic-feet-per-day 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 continue throughout 2019. The expected production loss in 2019 is
approximately 7 MBOED.
(cid:120) Helena Condensate Processing Facility(cid:178)We operate and own the Helena Condensate Processing
Facility, a 110,000 barrel-per-day condensate processing plant located in Kenedy, Texas.
(cid:120) Sugarloaf Condensate Processing Facility(cid:178)We operate and own an 87.5 percent interest in the
Sugarloaf Condensate Processing Facility, a 30,000 barrel-per-day condensate processing plant
located near Pawnee, Texas.
(cid:120) Bordovsky Condensate Processing Facility(cid:178)We operate and own the Bordovsky Condensate
Processing Facility, a 15,000 barrel-per-day condensate processing plant located in Kenedy, Texas.
7
CANADA
Our Canadian operations mainly consist of an oil sands development in the Athabasca Region of northeastern
Alberta and a liquids-rich unconventional play in western Canada. In 2018, operations in Canada contributed
8 percent of our worldwide liquids production and less than 1 percent of our natural gas production.
2018
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
-
2
2
-
12
12
66
-
66
66
4
70
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. Production from the assets sold was
103 MBOED, approximately 62 percent of the total Canada segment production in 2017. For additional
information on our asset dispositions, see Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned
Dispositions, in the Notes to Consolidated Financial Statements.
Oil Sands
Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called steam-
assisted gravity drainage (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
greenhouse gas intensity and optimizing asset performance.
Exploration
We hold exploration acreage in three areas of Canada: onshore western Canada, the Mackenzie Delta/Beaufort
Sea Region and the Arctic Islands. Our primary exploration focus is on unconventional plays in western
Canada.
We hold approximately 145,000 net acres in the emerging unconventional Montney play in northeast British
Columbia and 207,000 net acres in Canol Northwest Territories. Our Montney activity in 2018 included
drilling 13 horizontal wells, completing two horizontal wells and acquiring approximately 37,000 additional
net acres. Appraisal drilling and completions activity will continue in 2019 to further explore the (cid:68)(cid:85)(cid:72)(cid:68)(cid:182)(cid:86)(cid:3)
resource potential.
8
EUROPE AND NORTH AFRICA
The Europe and North Africa segment consists of operations and exploration activities in Norway, the United
Kingdom and Libya. In 2018, operations in Europe and North Africa contributed 19 percent of our worldwide
liquids production and 18 percent of natural gas production.
Norway
Average Daily Net Production
Greater Ekofisk Area
Heidrun
Alvheim
Visund
Troll
Other
Total Norway
Interest
Operator
35.1 % ConocoPhillips
Equinor
24.0
Aker BP
20.0
Equinor
9.1
Equinor
1.6
Equinor
Various
2018
Liquids Natural Gas
Total
MBD MMCFD MBOED
53
12
11
5
2
8
91
45
25
11
44
60
9
194
60
16
13
12
12
10
123
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 which achieved
first production in 2013 and 2015, respectively. Continued development drilling in the Greater Ekofisk Area
will 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 floating production, storage and offloading (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.
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,
as well as the Aasta Hansteen development in the Norwegian Sea, which achieved first production in
December 2018.
9
Exploration
In 2018, we participated in the Gekko appraisal well and sidetrack in the Alvheim Area of the North Sea and
encountered hydrocarbons. The Gekko Discovery is currently under evaluation as a future tie-in to the
Alvheim Facility. In 2018, we were awarded six new exploration licenses; PL911, PL912, PL917, PL919,
PL935 and PL938; and one acreage addition, PL775B.
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 natural gas liquids processing facility in Teesside, England.
United Kingdom
Interest
Operator
Average Daily Net Production
Britannia
Britannia Satellites
J-Area
Clair
East Irish Sea
Southern North Sea
Other
Total United Kingdom
*Includes the Chevron-operated Alder Field, ConocoPhillips equity interest is 26.3 percent.
**See dispositions below for additional information.
58.7 % ConocoPhillips
26.3(cid:177)93.8 * ConocoPhillips
ConocoPhillips
32.5(cid:177)36.5
BP
Spirit Energy
ConocoPhillips
Various
100.0
Various
Various
7.5 **
2018
Liquids
Natural
Gas
MBD MMCFD
Total
MBOED
3
12
9
6
-
-
-
30
74
92
57
1
30
22
5
281
15
27
19
6
5
4
1
77
Britannia is one of the largest natural gas and condensate fields in the North Sea. Condensate is delivered
through the Forties Pipeline to an oil stabilization and processing plant near the Grangemouth Refinery in
Scotland, while natural gas is transport(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:85)(cid:82)(cid:88)(cid:74)(cid:75)(cid:3)(cid:37)(cid:85)(cid:76)(cid:87)(cid:68)(cid:81)(cid:81)(cid:76)(cid:68)(cid:182)(cid:86)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:87)(cid:17)(cid:3)(cid:41)(cid:72)(cid:85)(cid:74)(cid:88)(cid:86)(cid:15)(cid:3)(cid:54)(cid:70)(cid:82)(cid:87)(cid:79)(cid:68)(cid:81)(cid:71)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:37)(cid:85)(cid:76)(cid:87)(cid:68)(cid:81)(cid:81)(cid:76)(cid:68)(cid:3)
satellite fields, Callanish, Brodgar, Enochdhu and Alder, produce via subsea manifolds and pipelines linked to
the Britannia Platform.
The J-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. The
J-Area gas is processed on the Judy Platform and transported through the Central Area Transmission System
Pipeline, while liquids are transported to Teesside through the Norpipe system. Continued development
drilling in the J-Area will provide additional volumes in the coming years as wells are brought online.
We have various ownership interests in several gas fields in the Rotliegendes and Carboniferous areas of the
Southern North Sea. Production ceased in August 2018, and decommissioning activity in the Southern North
Sea is ongoing. Our interests in the East Irish Sea include the Millom, Dalton and Calder fields, which are
operated on our behalf by a third party.
We own a 7.5 percent interest in the Clair Field, located in the Atlantic Margin. We completed the sale of a
(cid:86)(cid:88)(cid:69)(cid:86)(cid:76)(cid:71)(cid:76)(cid:68)(cid:85)(cid:92)(cid:3)(cid:75)(cid:82)(cid:79)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:3)(cid:20)(cid:25)(cid:17)(cid:24)(cid:3)(cid:83)(cid:72)(cid:85)(cid:70)(cid:72)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:38)(cid:79)(cid:68)(cid:76)(cid:85)(cid:3)(cid:41)(cid:76)(cid:72)(cid:79)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:3)(cid:87)(cid:82)(cid:3)(cid:37)(cid:51)(cid:17)(cid:3)(cid:3)(cid:54)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:39)(cid:76)(cid:86)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:180)(cid:3)
section below for more information. Clair Ridge is the second phase of development for the Clair Field and is
comprised of a 36-slot drilling and production facility with a bridge-linked accommodation and utilities
platform. The new facilities tie into existing oil and gas export pipelines to the Shetland Islands. First
production for Clair Ridge was achieved in November 2018.
10
Exploration
In 2018, we drilled the Jasmine 2A exploration well. The well encountered insufficient hydrocarbons and was
expensed as a dry hole. In 2018, we were awarded two new exploration licenses in the J-Area, P2399 and
P2456.
Transportation
We operate the Teesside oil and Theddlethorpe gas terminals in which we have 40.25 percent and 50 percent
ownership interests, respectively. Decommissioning activity is ongoing at the Theddlethorpe gas terminal
following cessation of production in the Southern North Sea. We also have a 100 percent ownership interest in
the Rivers Gas Terminal, operated by a third party.
Disposition
In the fourth quarter of 2018, we completed a transaction to sell a ConocoPhillips subsidiary, which held
16.5 percent of our 24 percent interest in the BP-operated Clair Field in the United Kingdom to BP, and
acquire their nonoperated interest in the Kuparuk Assets in Alaska. In 2018, our Europe and North Africa
segment net production associated with the disposed 16.5 percent interest in the Clair Field was approximately
5 MBOED. See Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes
to Consolidated Financial Statements, for additional information.
Libya
Interest
Operator
Liquids
MBD
2018
Natural
Gas
Total
MMCFD MBOED
Average Daily Net Production
Waha Concession
Total Libya
16.3 %
Waha Oil Co.
36
36
28
28
41
41
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 2018, we had 21 crude
liftings from Es Sider. We expect a gradual, continued rampup in activity.
11
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 2018, operations in the Asia
Pacific and Middle East segment contributed 14 percent of our worldwide liquids production and 60 percent of
natural gas production.
Australia and Timor Sea
2018
Average Daily Net Production
Australia Pacific LNG
Bayu-Undan
Athena/Perseus
Total Australia and Timor Sea
Interest
Operator
ConocoPhillips/
Origin Energy
ConocoPhillips
ExxonMobil
37.5 %
56.9
50.0
Natural
Gas
Liquids
Total
MBD MMCFD MBOED
-
7
-
7
660
240
35
935
110
47
6
163
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 coalbed methane (CBM) from the Bowen and
Surat basins in Queensland, Australia, to supply the domestic gas market and convert the CBM into LNG for
(cid:72)(cid:91)(cid:83)(cid:82)(cid:85)(cid:87)(cid:17)(cid:3)(cid:3)(cid:50)(cid:85)(cid:76)(cid:74)(cid:76)(cid:81)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:86)(cid:3)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:182)(cid:86)(cid:3)(cid:88)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:76)(cid:83)(cid:72)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:86)(cid:92)(cid:86)(cid:87)(cid:72)(cid:80)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:72)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:71)(cid:82)(cid:90)(cid:81)(cid:86)tream
LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business.
Two fully subscribed 4.5-million-metric-tonnes-per-year LNG trains have been completed. Approximately
3,900 net wells are ultimately expected to supply both the domestic gas market and the LNG sales contracts.
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 first APLNG
Train 1 cargo sailed in January 2016, and APLNG Train 2 achieved first production in the third quarter of
2016. 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.
APLNG has an $8.5 billion project finance facility, which was fully drawn down and had an outstanding
balance of $7.2 billion at December 31, 2018. In September 2018, APLNG successfully refinanced
$1.4 billion of the project finance facility for a lower cost United States Private Placement (USPP) bond
facility. Project finance interest payments are bi-annual, concluding September 2030.
For additional information, see Note 3(cid:178)Variable Interest Entities (VIEs), Note 6(cid:178)Investments, Loans and
Long-Term Receivables, and Note 12(cid:178)Guarantees, in the Notes to Consolidated Financial Statements.
Bayu-Undan
The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between
Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG
Facility, located at Wickham Point, Darwin.
The Bayu-Undan natural gas recycle facility processes wet gas; separates, stores and offloads condensate,
propane and butane; and re-injects dry gas back into the reservoir. In addition, a 310-mile natural gas pipeline
connects the facility to the 3.5-million-metric-tonnes-per-year capacity Darwin LNG Facility. Produced
12
natural gas is piped to the Darwin LNG Plant, where it is converted into LNG before being transported to
international markets. In 2018, we sold 157 billion gross cubic feet of LNG primarily to utility customers in
Japan.
A continuation of the Bayu-Undan Phase Three Development consisting of one subsea and two platform wells
was completed with all three wells producing by November 2018.
Athena/Perseus
The Athena production license (WA-17-L) in which ConocoPhillips has a 50 percent working interest is
located offshore Western Australia and contains part of the Perseus Field which straddles the boundary with
WA-1-L, an adjoining license area. The production entitlement to natural gas produced from WA-17-L is
forecast to end in the fourth quarter of 2019. (cid:3)
Greater Sunrise
In the fourth quarter of 2018, we entered into an agreement to sell our 30 percent interest in the Greater Sunrise
Fields to the government of Timor-Leste for $350 million, subject to customary adjustments. The transaction
is conditional on the funding approval from the Timor-Leste government as well as regulatory approvals.
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. The TP 28
Western Australia State exploration permit was granted for five years from January 2017, with a 40 percent
working interest and was excised from the existing permits as agreed between state and federal regulators.
Phase I of the Browse Basin drilling campaign in 2009/2010 resulted in three discoveries in the Greater
Poseidon Area: Poseidon-1, Poseidon-2 and Kronos-1. Phase II of the drilling campaign resulted in five
additional discoveries: Boreas-1, Zephyros-1, Proteus-1 SD2, Poseidon-North-1 and Pharos-1. 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 leases NT/RL5 and NT/RL6, containing the Barossa and Caldita discoveries. A 3-D
seismic survey was completed over the Barossa and Caldita fields in 2016. The drilling of the Barossa-5A and
Barossa-6 appraisal wells was completed in 2017 with good quality, gas-bearing reservoir intersected at both.
Additionally, the retention lease over the Barossa Field was renewed during 2017. In April 2018, Barossa
entered the front-end engineering and design (FEED) phase of development which will continue 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.
Indonesia
Average Daily Net Production
South Sumatra
Total Indonesia
Interest
Operator
45.0(cid:177)54.0 %
ConocoPhillips
2018
Natural
Gas
MBD MMCFD
Liquids
Total
MBOED
2
2
309
309
53
53
(cid:58)(cid:72)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:87)(cid:75)(cid:85)(cid:72)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:86)(cid:3)(cid:11)(cid:51)(cid:54)(cid:38)(cid:12)(cid:3)(cid:76)(cid:81)(cid:3)(cid:44)(cid:81)(cid:71)(cid:82)(cid:81)(cid:72)(cid:86)(cid:76)(cid:68)(cid:29)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:38)(cid:82)(cid:85)(cid:85)(cid:76)(cid:71)(cid:82)(cid:85)(cid:3)(cid:37)(cid:79)(cid:82)(cid:70)(cid:78)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:82)(cid:88)(cid:87)(cid:75)(cid:3)(cid:45)(cid:68)(cid:80)(cid:69)(cid:76)(cid:3)(cid:179)(cid:37)(cid:15)(cid:180)(cid:3)
both located in South Sumatra, and Kualakurun in Central Kalimantan. Currently, there is production from the
Corridor Block.
13
South Sumatra
The Corridor PSC consists of five oil fields and seven natural gas fields in various stages of development.
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. Production from the South Jambi (cid:179)(cid:37)(cid:180)(cid:3)(cid:51)(cid:54)(cid:38)(cid:3)(cid:75)(cid:68)(cid:86)(cid:3)
reached depletion and field development has been suspended. This PSC will expire in January 2020.
Exploration
We have a 60 percent working interest in the Kualakurun PSC, located in Central Kalimantan, which was
signed in May 2015. This block has an area of approximately 1.4 million gross acres. Technical evaluation is
on-going to determine the (cid:69)(cid:79)(cid:82)(cid:70)(cid:78)(cid:182)(cid:86) potential.
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
2018
Natural
Gas
MBD MMCFD
Liquids
Total
MBOED
30
6
36
-
-
-
30
6
36
The Penglai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from Phase 1
development of the Penglai 19-3 Field began in 2002. Phase 2, which included six additional wellhead platforms
and an FPSO vessel, was fully operational by 2009.
As part of further development of the Penglai 19-9 Field, the new wellhead platform J Project, which anticipates
62 wells, is progressing according to schedule, with 36 wells completed and brought online through December
2018.
The Penglai 19-3/19-9 Phase 3 Project was sanctioned in December 2015. This project consists of three new
wellhead platforms and a central processing platform. First oil from Phase 3 was achieved in 2018. (cid:3)
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.
The Panyu development, located in Block 15/34 in the South China Sea, is comprised of three oil fields: Panyu
4-2, Panyu 5-1 and Panyu 11-6. The production period for Panyu 4-2, 5-1 and 11-6 will expire in 2019.
Exploration
In 2018, we participated in one successful appraisal well in the Bohai Penglai Field. We continued the Penglai
full-field 3-D seismic program, covering existing and future development opportunities. The program is
expected to complete in 2019.
14
Malaysia
Average Daily Net Production
Siakap North-Petai
Gumusut
KBB
Malikai
Total Malaysia
Interest
Operator
21.0 %
29.0
30.0
35.0
Murphy
Shell
KPOC
Shell
2018
Natural
Gas
MBD MMCFD
Liquids
Total
MBOED
2
25
1
19
47
1
-
41
-
42
2
25
8
19
54
We own interests in six PSCs in Malaysia. Three are located off the eastern Malaysian state of Sabah: Block
G, Block J and the Kebabangan Cluster (KBBC). Three other blocks, Block SK304, Block SK313 and Block
WL4-00 are located off the eastern Malaysian state of Sarawak.
Block G
We have a 21 percent interest in the unitized Siakap North-Petai oil field, which began producing in the first
quarter of 2014.
We own a 35 percent interest in Malikai. The field achieved first production in December 2016, ramping to
peak production in 2018. The KMU-1 exploration well was completed and started producing in 2018.
Block J
First production from the Gumusut Field occurred from an early production system in 2012. Production from
a permanent, semi-submersible floating production vessel was achieved in October 2014. Our ownership in
the Gumusut Field is currently at 29 percent following the finalization of the Malaysia-Brunei unitization and a
redetermination of the Block J and Block K Malaysia Unit, both in 2017. The drilling of the Gemilang-1
exploration well in Block J is complete and the results are under review. Gumusut Phase 2 infill drilling and
first oil from Phase 2 are expected in 2019.
KBBC
We have a 30 percent interest in the KBBC PSC. Development of the KBB gas field commenced in 2011, and
first production was achieved in November 2014. Production in 2018 was impacted by unplanned downtime
related to the rupture of a third-party pipeline which carries gas production from the Kebabangan gas field to
market. Development options for the Kamunsu East gas field are being evaluated.
Exploration
In the fourth quarter of 2016, we entered into a farm-in agreement to acquire a 50 percent interest in Block SK
313, a 1.4 million gross-acre exploration block, effective January 2017. Following completion of the Sadok-1
exploration well in January 2017, we assumed operatorship of the block from PETRONAS.
We were awarded Block WL4-00, which encompasses 0.6 million gross acres, in January 2017. We have a
50 percent operated interest in this block which includes the Salam-1 oil discovery.
We completed a 3-D seismic survey in Block SK 313 and Block WL4-00 in 2017. Two wells were drilled in
Block WL4-00 in 2018 and discovered hydrocarbons. Further exploration drilling is expected to occur in
2019.
We were awarded Block SK304 in May 2018, which encompasses 2.1 million gross acres. We completed a
3-D seismic survey in this block in 2018.
15
Brunei
Exploration
In October 2018, we assigned our 6.25 percent working interest in the deepwater Block CA-2 PSC to Brunei
National Petroleum Company Sendirian Berhad.
Qatar
Average Daily Net Production
QG3
Total Qatar
Interest
Operator
Liquids
MBD
2018
Natural
Gas
Total
MMCFD MBOED
30.0 %
Qatargas Operating
Company Limited
21
21
371
371
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 (cid:69)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:74)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:70)(cid:88)(cid:69)(cid:76)(cid:70)(cid:3)(cid:73)(cid:72)(cid:72)(cid:87)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:71)(cid:68)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:52)(cid:68)(cid:87)(cid:68)(cid:85)(cid:182)(cid:86)(cid:3)(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:3)(cid:41)(cid:76)(cid:72)(cid:79)(cid:71)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)
a 25-year life, in addition to a 7.8 million gross tonnes-per-year LNG facility. LNG is shipped in leased LNG
carriers destined for sale globally.
QG3 executed the development of the onshore and offshore assets as a single integrated development with
Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint
development of offshore facilities situated in a common offshore block in the North Field, as well as the
construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and
QG4 joint ventures. Production from the LNG trains and associated facilities is combined and shared.
OTHER INTERNATIONAL
The Other International segment includes exploration activities in Colombia and Chile.
Colombia
Exploration
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 is expected to continue into 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. Community engagement and environmental
permitting activities are expected to continue in 2019.
Chile
Exploration
We have a 49 percent interest in the Coiron Block located in the Magallanes Basin in southern Chile.
Argentina
Exploration
We received government approval in January 2019 for a 50 percent nonoperated interest in the El Turbio Este
Block in the Austral Basin.
Venezuela and Ecuador
For discussion of our contingencies in Venezuela and Ecuador, see Note 13(cid:178)Contingencies and
Commitments, in the Notes to Consolidated Financial Statements.
16
OTHER
Marketing Activities
Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural
gas, crude oil, bitumen, natural gas liquids and LNG. Marketing activities are performed through offices in the
United States, 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 United States,
Canada, Europe and Asia. Our natural gas is sold to a diverse client portfolio which includes local distribution
companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas
companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport
natural gas via firm and interruptible transportation agreements to major market hubs.
Crude Oil, Bitumen and Natural Gas Liquids
Our crude oil, bitumen and natural gas liquids revenues are derived from production in the United States,
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
(cid:70)(cid:82)(cid:81)(cid:87)(cid:68)(cid:76)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:72)(cid:70)(cid:75)(cid:81)(cid:82)(cid:79)(cid:82)(cid:74)(cid:92)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:71)(cid:72)(cid:72)(cid:83)(cid:90)(cid:68)(cid:87)(cid:72)(cid:85)(cid:3)(cid:56)(cid:17)(cid:54)(cid:17)(cid:3)(cid:42)(cid:88)(cid:79)(cid:73)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:72)(cid:91)(cid:76)(cid:70)(cid:82)(cid:17)(cid:3)(cid:3)(cid:48)(cid:58)(cid:38)(cid:38)(cid:182)(cid:86)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:68)(cid:76)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:86)(cid:92)(cid:86)(cid:87)(cid:72)(cid:80)(cid:3)
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(cid:178)Variable Interest Entities (VIEs), 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
(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:54)(cid:87)(cid:68)(cid:89)(cid:68)(cid:81)(cid:74)(cid:72)(cid:85)(cid:15)(cid:3)(cid:49)(cid:82)(cid:85)(cid:90)(cid:68)(cid:92)(cid:15)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:70)(cid:85)(cid:72)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:72)(cid:81)(cid:75)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:76)(cid:81)(cid:71)(cid:88)(cid:86)(cid:87)(cid:85)(cid:92)(cid:182)(cid:86)(cid:3)(cid:70)(cid:68)(cid:83)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:76)nternational
subsea well control incidents. Through collaboration with Oil Spill Response Limited, a non-profit
organization in the United Kingdom, 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 United States by
MWCC and provides well capping and containment capability outside the United States.
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 United Kingdom, 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.
17
Technology
We have several technology programs that improve our ability to develop unconventional reservoirs, produce
heavy oil economically with fewer emissions, improve the efficiency of our (cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86) 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.
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, 2018. No difference exists between our estimated total proved reserves
for year-end 2017 and year-end 2016, which are shown in this filing, and estimates of these reserves shown in
a filing with another federal agency in 2018.
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 1.5 trillion cubic feet of natural gas, including approximately 243 billion cubic feet
related to the noncontrolling interests of consolidated subsidiaries, and 73 million barrels of crude oil in the
future. These contracts have various expiration dates through the year 2029. We expect to fulfill the majority
of these delivery commitments with proved developed reserves. In addition, we anticipate using proved
undeveloped reserves and spot market purchases to fulfill any remaining commitments. See the disclosure on
(cid:179)(cid:51)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:3)(cid:56)(cid:81)(cid:71)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:72)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:180)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:68)(cid:86)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:73)(cid:82)(cid:79)(cid:79)(cid:82)(cid:90)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:38)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)
Financial Statements, for information on the development of proved undeveloped reserves.
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, natural gas liquids and natural gas in an efficient,
cost-effective manner. Based on statistics published in the September 3, 2018, 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 2017. We deliver our production into the worldwide commodity
markets. Principal methods of competing include geological, geophysical and engineering research and
technology; experience and expertise; economic analysis in connection with portfolio management; and safely
operating oil and gas producing properties.
18
GENERAL
At the end of 2018, we held a total of 814 active patents in 50 countries worldwide, including 333 active U.S.
patents. During 2018, we received 29 patents in the United States and 67 foreign patents. Our products and
processes generated licensing revenues of $53 million related to activity in 2018. The overall profitability of
any business segment is not dependent on any single patent, trademark, license, franchise or concession.
Health, Safety and Environment
Our Health, Safety and Environment (HSE) organization provides tools and support to our business units and
staff groups to help them ensure world class health, safety and environmental 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 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 also have detailed processes in place to address
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.
(cid:55)(cid:75)(cid:72)(cid:3)(cid:72)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:68)(cid:76)(cid:81)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
and Results of Operations on pages 65 through 69 (cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:68)(cid:83)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:179)(cid:40)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:179)(cid:38)(cid:79)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:3)(cid:38)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:180)(cid:3)
is incorporated herein by reference. It includes information on expensed and capitalized environmental costs
for 2018 and those expected for 2019 and 2020.
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 U.S. Securities and Exchange Commission (SEC). Alternatively, you may
(cid:68)(cid:70)(cid:70)(cid:72)(cid:86)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:86)(cid:3)(cid:68)(cid:87)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:40)(cid:38)(cid:182)(cid:86)(cid:3)(cid:90)(cid:72)(cid:69)(cid:86)(cid:76)(cid:87)(cid:72)(cid:3)(cid:68)(cid:87)(cid:3)www.sec.gov.
19
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, natural gas liquids and LNG can fluctuate widely. Globally, prices
for crude oil, bitumen, natural gas, natural gas liquids and LNG have experienced significant declines from
their historic levels during 2013 and 2014, with excess of supply relative to global demand leading to global
inventory builds. Although commodity prices began to rise in 2018, there was a sharp drop in crude oil prices
in the fourth quarter of 2018, ending 2018 lower than where they started at the beginning of the year for the
first time since 2015. Given volatility in commodity price drivers and the worldwide economic environment
generally, 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, natural gas liquids and LNG. The factors influencing these prices are beyond
our control.
Lower crude oil, bitumen, natural gas, natural gas liquids and LNG prices may have a material adverse effect
on our revenues, operating income, cash flows and liquidity, and on the amount of dividends we elect to
declare and pay on our common stock. Lower prices may also limit the amount of reserves we can produce
economically, adversely affecting our proved reserves and 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, natural gas liquids 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(cid:178)(cid:44)(cid:80)(cid:83)(cid:68)(cid:76)(cid:85)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:3)(cid:25)(cid:178)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:
(cid:120) Cash available for distribution.
(cid:120) Our results of operations and anticipated future results of operations.
(cid:120) Our financial condition, especially in relation to the anticipated future capital needs of our properties.
(cid:120) The level of distributions paid by comparable companies.
(cid:120) Our operating expenses.
(cid:120) Other factors our Board of Directors deems relevant.
20
We expect to continue to pay quarterly distributions to our stockholders; however, our Board of Directors may
determine that our funds generated by operations, after deducting operating expenses, are not sufficient to pay
our desired levels of distributions to our stockholders or to pay distributions to our stockholders at all.
Additionally, our Board of Directors has authorized a $15 billion share repurchase program, of which
$9 billion of repurchase authority remained as of December 31, 2018. 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 distributions, among others.
Any downward revision in the amount of distributions 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. For example, due to the
significant decline in prices for crude oil, bitumen, natural gas, natural gas liquids and LNG in 2015, and the
expectation that these prices could remain depressed, the major ratings agencies conducted a review of the oil
and gas industry and downgraded our debt ratings and those of several companies operating in the industry in
2016. 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.
21
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
(cid:82)(cid:81)(cid:3)(cid:68)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:88)(cid:68)(cid:79)(cid:3)(cid:71)(cid:76)(cid:86)(cid:83)(cid:88)(cid:87)(cid:72)(cid:3)(cid:68)(cid:85)(cid:76)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:57)(cid:72)(cid:81)(cid:72)(cid:93)(cid:88)(cid:72)(cid:79)(cid:68)(cid:182)(cid:86)(cid:3)(cid:72)(cid:91)(cid:83)(cid:85)(cid:82)(cid:83)(cid:85)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:51)(cid:72)(cid:87)(cid:85)(cid:82)(cid:93)(cid:88)(cid:68)(cid:87)(cid:68)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:43)(cid:68)(cid:80)(cid:68)(cid:70)(cid:68)(cid:3)
heavy oil ventures and other pre-expropriation fiscal measures. We collected approximately $0.4 billion of the
$2 billion settlement in 2018. If PDVSA were to default on any of its remaining payment obligations under
this agreement, we may be forced to incur additional costs as we seek to recover any unpaid amounts under the
agreement.
Unless we successfully add to our existing proved reserves, our future crude oil, bitumen, natural gas and
natural gas liquids production will decline, resulting in an adverse impact to our business.
The rate of production from upstream fields generally declines as reserves are depleted. Except to the extent
that we 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 natural gas liquids. Accordingly, to the extent we
are unsuccessful in replacing the crude oil, bitumen, natural gas and natural gas liquids we produce with good
prospects for future production, 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 natural gas liquids 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 natural gas liquids 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 natural gas liquids reserves could impair the quantity and value of those reserves.
Our proved reserve information included in this annual report has been derived from engineering estimates
prepared by our personnel. Reserve estimation is a process that involves estimating volumes to be recovered
from underground accumulations of crude oil, bitumen, natural gas and natural gas liquids that cannot be
directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and
engineering practices and scientific methods, may produce different estimates of reserves and future net cash
flows based on the same available data. Any significant future price changes could have a material effect on
the quantity and present value of our proved reserves. 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. In addition to changes in the quantity and value of our proved reserves, the amount of crude oil,
bitumen, natural gas and natural gas liquids that can be obtained from any proved reserve may ultimately be
different from those estimated prior to extraction.
22
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 United States and in other
countries in which we operate. For a description of the most significant of these environmental laws and
(cid:85)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86)(cid:178)(cid:40)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)
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:
(cid:120) Permits required in connection with exploration, drilling, production and other activities.
(cid:120) The discharge of pollutants into the environment.
(cid:120) Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and greenhouse gas
emissions.
(cid:120) Carbon taxes.
(cid:120) The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous
and nonhazardous wastes.
(cid:120) The dismantlement, abandonment and restoration of our properties and facilities at the end of their
useful lives.
(cid:120) Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil
sands reservoirs and tight oil plays.
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 greenhouse gas 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
greenhouse gas 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
United States 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 greenhouse gas emission reduction goals every five years
beginning in 2020. While the United States announced its intention to withdraw from the Paris Agreement,
there is no guarantee that the commitments made by the United States will not be implemented, in whole or in
part, by U.S. state and local governments or by major corporations headquartered in the United States. 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 greenhouse gas
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 greenhouse gases 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.
23
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, a state government, and a trade association in California, New
York, Washington, Rhode Island and Maryland have filed lawsuits against several 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 our business operations are designed and operated to accommodate expected climatic
conditions, to the extent there are significant changes in the earth(cid:182)(cid:86)(cid:3)(cid:70)(cid:79)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:15)(cid:3)(cid:86)(cid:88)(cid:70)(cid:75)(cid:3)(cid:68)(cid:86)(cid:3)(cid:80)(cid:82)(cid:85)(cid:72)(cid:3)(cid:86)(cid:72)(cid:89)(cid:72)(cid:85)(cid:72)(cid:3)(cid:82)(cid:85)(cid:3)(cid:73)(cid:85)(cid:72)(cid:84)(cid:88)(cid:72)(cid:81)(cid:87)(cid:3)
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
(cid:68)(cid:73)(cid:73)(cid:72)(cid:70)(cid:87)(cid:3)(cid:82)(cid:85)(cid:3)(cid:70)(cid:82)(cid:88)(cid:79)(cid:71)(cid:3)(cid:68)(cid:73)(cid:73)(cid:72)(cid:70)(cid:87)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:3)(cid:71)(cid:72)(cid:86)(cid:70)(cid:85)(cid:76)(cid:83)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:72)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86)(cid:178)
(cid:38)(cid:79)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:3)(cid:38)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)
Operations.
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 United States
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. Environmental Protection Agency (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.
24
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 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 55 percent of our hydrocarbon production was derived from production outside the United
States in 2018, and 41 percent of our proved reserves, as of December 31, 2018, were located outside the
United States. We are subject to risks associated with operations in international markets, including changes in
foreign governmental policies relating to crude oil, natural gas, bitumen, natural gas liquids 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 particular, some countries where we operate lack well-developed legal systems or have not
adopted clear legal and regulatory frameworks for oil and gas exploration and production. This lack of legal
certainty 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.
Our business may be adversely affected by price controls, government-imposed limitations on production of
crude oil, bitumen, natural gas and natural gas liquids, or the unavailability of adequate gathering,
processing, compression, transportation, and pipeline facilities and equipment for our production of crude
oil, bitumen, natural gas and natural gas liquids.
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 natural gas liquids 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, natural gas liquids 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, natural gas liquids 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, natural gas liquids and LNG for sale or we may be forced to
curtail our production of crude oil, bitumen, natural gas, natural gas liquids or LNG.
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.
25
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.
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.
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,
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. Activities in deepwater areas 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.
26
Although we have experienced occasional, actual or attempted 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
2018, as well as matters previously reported in our 2017 Form 10-K and our first-, second- and third-quarter
2018 Form 10-Qs that were not resolved prior to the fourth quarter of 2018. 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,
through the payment of a penalty of $457,750 and the implementation of measures designed to prevent a
reoccurrence. The company will work with the Commission to promptly resolve this matter.
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
28
EXECUTIVE OFFICERS OF THE REGISTRANT
Name
Position Held
Age*
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
53
54
62
58
52
56
58
49
52
60
*On February 15, 2019.
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 14, 2019. 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(cid:178)International since May
2009.
29
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.
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
(cid:44)(cid:87)(cid:72)(cid:80)(cid:3)(cid:24)(cid:17)(cid:3)(cid:3)(cid:3)(cid:3)(cid:48)(cid:36)(cid:53)(cid:46)(cid:40)(cid:55)(cid:3)(cid:41)(cid:50)(cid:53)(cid:3)(cid:53)(cid:40)(cid:42)(cid:44)(cid:54)(cid:55)(cid:53)(cid:36)(cid:49)(cid:55)(cid:182)(cid:54)(cid:3)(cid:38)(cid:50)(cid:48)(cid:48)(cid:50)(cid:49)(cid:3)(cid:40)(cid:52)(cid:56)(cid:44)(cid:55)(cid:60)(cid:15)(cid:3)(cid:53)(cid:40)(cid:47)(cid:36)(cid:55)(cid:40)(cid:39)(cid:3)(cid:54)(cid:55)(cid:50)(cid:38)(cid:46)(cid:43)(cid:50)(cid:47)(cid:39)(cid:40)(cid:53)(cid:3)
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:85)(cid:68)(cid:71)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:49)(cid:72)(cid:90)(cid:3)(cid:60)(cid:82)(cid:85)(cid:78)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:15)(cid:3)(cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:92)(cid:80)(cid:69)(cid:82)(cid:79)(cid:3)(cid:179)(cid:38)(cid:50)(cid:51)(cid:17)(cid:180)
Cash Dividends Per Share
First
Second
Third
Fourth
Dividends
2018
$
0.285
0.285
0.285
0.305
2017
0.265
0.265
0.265
0.265
Number of Stockholders of Record at January 31, 2019*
*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency
listing.
44,084
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 January 31, 2017, we announced that our Board of Directors approved an increase in the quarterly dividend
to $0.265 per share, compared with the previous quarterly dividend of $0.25 per share.
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.
31
Issuer Purchases of Equity Securities
Period
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
October 1-31, 2018
9,492
November 1-30, 2018
9,183
December 1-31, 2018
8,875
8,875
Total fourth-quarter 2018
*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.
4,155,118
4,642,077
4,808,691
13,605,886
4,155,118
4,642,077
4,808,691
13,605,886
74.45
66.57
63.87
68.02
$
$
$
$
On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock through 2019.
On March 29, 2017, we announced plans to double our share repurchase program to $6 billion of common
stock through 2019, with $3 billion allocated and purchased in 2017, and the remainder allocated evenly to
2018 and 2019. On February 1, 2018, we announced the acceleration of our previously stated 2018 share
repurchases from $1.5 billion to $2 billion. On July 12, 2018, we announced plans to further accelerate our
2018 share repurchases to $3 billion. The 2018 expansion to $3 billion, combined with the $3 billion of shares
(cid:85)(cid:72)(cid:83)(cid:88)(cid:85)(cid:70)(cid:75)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:71)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:21)(cid:19)(cid:20)(cid:25)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:21)(cid:19)(cid:20)(cid:26)(cid:15)(cid:3)(cid:73)(cid:88)(cid:79)(cid:79)(cid:92)(cid:3)(cid:88)(cid:87)(cid:76)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:37)(cid:82)(cid:68)(cid:85)(cid:71)(cid:3)(cid:82)(cid:73)(cid:3)(cid:39)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:182)(cid:3)(cid:72)(cid:91)(cid:76)(cid:86)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:3)(cid:85)(cid:72)(cid:83)(cid:88)(cid:85)(cid:70)(cid:75)(cid:68)(cid:86)(cid:72)(cid:3)
authorization of $6 billion. As a result, our Board authorized an additional $9 billion for share repurchases, at
any time or from time to time (whether before, on or after December 31, 2019), bringing the total program
authorization to $15 billion. Acquisitions f(cid:82)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:3)(cid:85)(cid:72)(cid:83)(cid:88)(cid:85)(cid:70)(cid:75)(cid:68)(cid:86)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:80)(cid:68)(cid:71)(cid:72)(cid:3)(cid:68)(cid:87)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)
discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased,
decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are
(cid:75)(cid:72)(cid:79)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:85)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:92)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:17)(cid:3)(cid:3)(cid:54)(cid:72)(cid:72)(cid:3)(cid:53)(cid:76)(cid:86)(cid:78)(cid:3)(cid:41)(cid:68)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:179)(cid:50)(cid:88)(cid:85)(cid:3)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:71)(cid:72)(cid:70)(cid:79)(cid:68)(cid:85)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:68)(cid:92)(cid:3)(cid:71)(cid:76)(cid:89)(cid:76)(cid:71)(cid:72)(cid:81)(cid:71)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:83)(cid:88)(cid:85)(cid:70)(cid:75)(cid:68)(cid:86)(cid:72)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)
(cid:86)(cid:88)(cid:69)(cid:77)(cid:72)(cid:70)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:70)(cid:72)(cid:85)(cid:87)(cid:68)(cid:76)(cid:81)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:180)
Stock Performance Graph
The following graph shows the cumulative total (cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:3)(cid:85)(cid:72)(cid:87)(cid:88)(cid:85)(cid:81)(cid:3)(cid:11)(cid:55)(cid:54)(cid:53)(cid:12)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)
in each of the five years from December 31, 2013, to December 31, 2018. The graph also compares the
cumulative total returns for the same five-year period with the S&P 500 Index and our performance peer group
consisting of BP, Chevron, ExxonMobil, Royal Dutch Shell, Total, Anadarko, Apache, Marathon Oil
(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:39)(cid:72)(cid:89)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:50)(cid:70)(cid:70)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:15)(cid:3)(cid:90)(cid:72)(cid:76)(cid:74)(cid:75)(cid:87)(cid:72)(cid:71)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:85)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:83)(cid:72)(cid:72)(cid:85)(cid:182)(cid:86)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:3)(cid:70)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:76)(cid:93)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:87)(cid:3)
the beginning of each annual period. The comparison assumes $100 was invested on December 31, 2013, in
(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:15)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:9)(cid:51)(cid:3)(cid:24)(cid:19)(cid:19)(cid:3)(cid:44)(cid:81)(cid:71)(cid:72)(cid:91)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:83)(cid:72)(cid:72)(cid:85)(cid:3)(cid:74)(cid:85)(cid:82)(cid:88)(cid:83)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:86)(cid:86)(cid:88)(cid:80)(cid:72)(cid:86)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:68)(cid:79)(cid:79)(cid:3)(cid:71)(cid:76)(cid:89)(cid:76)(cid:71)(cid:72)(cid:81)(cid:71)(cid:86)(cid:3)(cid:90)(cid:72)(cid:85)(cid:72)(cid:3)
reinvested.
32
Item 6. SELECTED FINANCIAL DATA
Sales and other operating revenues
Income (loss) from continuing operations
Per common share
Basic
Diluted
Income from discontinued operations
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
2018
2017
2016
2015
2014
$
36,417
6,305
29,106
(793)
23,693
(3,559)
29,564
(4,371)
52,524
5,807
5.36
5.32
-
6,305
6,257
5.36
5.32
69,980
14,856
1.16
(0.70)
(0.70)
-
(793)
(855)
(0.70)
(0.70)
73,362
17,128
1.06
(2.91)
(2.91)
-
(3,559)
(3,615)
(2.91)
(2.91)
89,772
26,186
1.00
(3.58)
(3.58)
-
(4,371)
(4,428)
4.63
4.60
1,131
6,938
6,869
(3.58)
(3.58)
97,484
23,453
2.94
5.54
5.51
116,539
22,383
2.84
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 interest in the San Juan Basin.
Net income (loss) and net income (loss) attributable to ConocoPhillips in 2014 includes income from
discontinued operations as a result of the sale of our interest in our Nigeria business.
These factors impact the comparability of historical information.
(cid:54)(cid:72)(cid:72)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)
Consolidated Financial Statements for a discussion of factors that will enhance an understanding of this data.
33
Item 7. (cid:48)(cid:36)(cid:49)(cid:36)(cid:42)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:182)(cid:54)(cid:3)(cid:39)(cid:44)(cid:54)(cid:38)(cid:56)(cid:54)(cid:54)(cid:44)(cid:50)(cid:49)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)(cid:36)(cid:49)(cid:36)(cid:47)(cid:60)(cid:54)(cid:44)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:41)(cid:44)(cid:49)(cid:36)(cid:49)(cid:38)(cid:44)(cid:36)(cid:47)(cid:3)(cid:38)(cid:50)(cid:49)(cid:39)(cid:44)(cid:55)(cid:44)(cid:50)(cid:49)(cid:3)(cid:36)(cid:49)(cid:39)(cid:3)
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 76.
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
(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:90)(cid:82)(cid:85)(cid:79)(cid:71)(cid:182)(cid:86)(cid:3)(cid:79)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:87)(cid:3)(cid:76)(cid:81)(cid:71)(cid:72)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:72)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:11)(cid:40)(cid:9)(cid:51)(cid:12)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:15)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)
proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have
operations and activities in 16 countries. Our diverse, low cost of supply portfolio includes resource-rich
unconventional plays in North America; lower-risk conventional assets in North America, Europe, Asia and
Australia; liquefied natural gas (LNG) developments; oil sands assets in Canada; and an inventory of global
conventional and unconventional exploration prospects. At December 31, 2018, we employed approximately
10,800 people worldwide and had total assets of $70 billion.
Overview
In 2018, the energy industry continued to be volatile. Forecasts of worldwide economic growth and strong
global demand for crude oil at the beginning of the year transitioned to concerns about a worldwide economic
slowdown and an oversupply of crude oil by the end of the year. Additionally, production from major oil
producing countries, including the United States, was strong. These factors caused crude oil prices to fall
rapidly in the fourth quarter of 2018. Our business strategy anticipates prices will remain cyclical and is
designed to be resilient in lower price environments, with significant upside during periods of higher prices.
Our value proposition principles, namely to focus on returns, maintain financial strength, grow our dividend
and pursue disciplined growth, are being executed in accordance with our priorities for allocating cash flows
from the business. These priorities are: invest capital at a level that maintains flat production volumes and
pays 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; repurchase shares to provide value to our
shareholders; and invest capital to grow our cash from operations.
In 2018, we successfully delivered on our priorities. We increased our quarterly dividend by 15 percent to
$0.305 per share; reduced our debt by $4.7 billion, achieving our debt reduction target 18 months ahead of plan
(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:72)(cid:71)(cid:3)(cid:70)(cid:85)(cid:72)(cid:71)(cid:76)(cid:87)(cid:3)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:88)(cid:83)(cid:74)(cid:85)(cid:68)(cid:71)(cid:72)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:41)(cid:76)(cid:87)(cid:70)(cid:75)(cid:15)(cid:3)(cid:48)(cid:82)(cid:82)(cid:71)(cid:92)(cid:182)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:3)(cid:9)(cid:3)(cid:51)(cid:82)(cid:82)(cid:85)(cid:182)(cid:86)(cid:30)(cid:3)(cid:85)(cid:72)(cid:83)(cid:88)(cid:85)(cid:70)(cid:75)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)45 million shares
of our common stock totaling $3.0 billion and received Board authorization for an incremental $9 billion of
share repurchases; and added to our low cost of supply resource base, including increasing our legacy asset
position in Alaska through two separate acquisitions.
34
Portfolio optimization, debt reduction and disciplined capital investment have positioned our company to
navigate through periods of volatile energy prices. In December 2018, we announced our 2019 capital budget
of $6.1 billion, which is less than our 2018 capital expenditures and investments of $6.8 billion. Our 2019
capital budget is relatively flat to the prior year when excluding $0.6 billion of acquisitions made in 2018. At
this level of capital, production excluding Libya is expected to be 1,300 to 1,350 thousand barrels of oil
equivalent per day (MBOED) in 2019 and would exceed 2018 production excluding Libya of 1,242 MBOED.
This plan anticipates cash provided by operating activities in excess of capital expenditures and investments at
prices above $40 per barrel West Texas Intermediate (WTI).
Key Operating and Financial Summary
Significant items during 2018 included the following:
(cid:120) Cash provided by operating activities was $12.9 billion and exceeded capital expenditures and
investments of $6.8 billion, share repurchases of $3 billion and dividends of $1.4 billion.
(cid:120) The $4.4 billion of share repurchases and dividends represents 34 percent of cash provided by
operating activities.
(cid:120) Reduced debt by $4.7 billion and achieved $15 billion debt target 18 months ahead of plan.
(cid:120) (cid:53)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:72)(cid:71)(cid:3)(cid:70)(cid:85)(cid:72)(cid:71)(cid:76)(cid:87)(cid:3)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:88)(cid:83)(cid:74)(cid:85)(cid:68)(cid:71)(cid:72)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:41)(cid:76)(cid:87)(cid:70)(cid:75)(cid:15)(cid:3)(cid:48)(cid:82)(cid:82)(cid:71)(cid:92)(cid:182)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:3)(cid:9)(cid:3)(cid:51)(cid:82)(cid:82)(cid:85)(cid:182)(cid:86)(cid:17)
(cid:120) Full-year production excluding Libya of 1,242 MBOED; underlying production grew 18 percent on a
production per debt-adjusted share basis.
(cid:120)
Increased full-year Lower 48 Big 3 production(cid:178)Eagle Ford, Bakken and Delaware(cid:178)by 37 percent.
(cid:120) Achieved first production from Bayu-Undan final development phase, GMT-1, Bohai Phase 3, Aasta
Hansteen and Clair Ridge.
(cid:120) Acquired additional working interest in our legacy assets in Alaska and increased our acreage in the
liquids-rich Montney play in Canada and in the early-life cycle unconventional Louisiana Austin
Chalk.
(cid:120) Executed successful exploration program in Alaska and started drilling in Louisiana Austin Chalk.
(cid:120) Reached a settlement agreement with Petroleos de Venezuela, S.A. (PDVSA) to fully recover the
International Chamber of Commerce (ICC) arbitration award of approximately $2 billion; recognized
$430 million before-tax toward the settlement.
(cid:120) Generated disposition proceeds of $1.1 billion from noncore asset sales.
(cid:120) Year-end proved reserves of 5.3 billion barrels of oil equivalent (BOE); 147 percent total reserve
replacement and 109 percent organic replacement ratio.
Operationally, we continue to focus on safely executing our capital program and remaining diligent on our
costs. Production, including Libya, of 1,283 MBOED decreased 7 percent in 2018 compared with 2017. The
volume from closed dispositions was approximately 200 MBOED in 2017 and 15 MBOED in 2018. The
volume from acquisitions was less than 10 MBOED in 2018. Production from Libya was 21 MBOED in 2017
and 41 MBOED in 2018. Our underlying production, which excludes the full-year impact of acquisitions,
dispositions, and Libya, increased over 5 percent in 2018 compared with 2017. Underlying production on a
per debt-adjusted share basis grew by 18 percent compared to 2017. Production per debt-adjusted share is
calculated on an underlying production basis using ending period debt divided by ending share price plus
ending shares outstanding. We believe production per debt-adjusted share is useful to investors as it provides a
consistent view of production on a total equity basis by converting debt to equity and allows for comparison
across peer companies.
In the second quarter of 2018, we obtained regulatory approvals and completed a transaction with Anadarko
Petroleum Corporation to acquire its 22 percent nonoperated interest in the Western North Slope of Alaska, as
well as its interest in the Alpine Transportation Pipeline, for $386 million, after customary adjustments. In
2018, our Alaska segment net production included 7 MBOED associated with the additional interest acquired.
In addition, we now have 100 percent interest in approximately 1.2 million acres of exploration and
development lands, including the Willow Discovery.
35
In the fourth quarter of 2018, we completed a transaction with BP to acquire its nonoperated interest in the
Greater Kuparuk Area and Kuparuk Transportation Company (Kuparuk Assets) in Alaska, and to sell a
ConocoPhillips subsidiary to BP, which held 16.5 percent of our 24 percent interest in the BP-operated Clair
Field in the United Kingdom. In 2018, our Alaska segment net production included 1 MBOED associated
with the additional interest acquired in the Greater Kuparuk Area, and net production in our Europe and North
Africa segment included 5 MBOED related to the disposed 16.5 percent interest in the Clair Field. We
recognized a $774 million after-tax gain in the fourth quarter related to this transaction. Excluding receipt of
$253 million in customary adjustments, this transaction was cash neutral.
In the fourth quarter of 2018, we completed the sale of our interests in the Barnett to Lime Rock Resources for
$196 million after customary adjustments. In 2018, our Lower 48 segment net production included 8 MBOED
related to the disposed interest in the Barnett, of which approximately 55 percent was natural gas and
45 percent was natural gas liquids. After-tax impairment charges of $69 million were recognized during 2018.
In the fourth quarter of 2018, we entered into an agreement to sell our 30 percent interest in the Greater Sunrise
Fields to the government of Timor-Leste for $350 million, subject to customary adjustments. The transaction
is conditional on the funding approval from the Timor-Leste government as well as regulatory approvals. No
production or reserve impacts are associated with the sale. Proceeds from this transaction will be used for
general corporate purposes. The Greater Sunrise Fields are included in our Asia Pacific and Middle East
segment.
For more information regarding the accounting impacts of these transactions, see Note 5(cid:178)Assets Held for
Sale, Sold or Acquired and Other Planned Dispositions, in the Notes to Consolidated Financial Statements.
Also during 2018, we entered into a settlement agreement with PDVSA to recover approximately $2 billion,
which reflects the full amount awarded to ConocoPhillips by an arbitral tribunal constituted under the rules of
the ICC. PDVSA has agreed to recognize the ICC judgment and to make payments over the next four and a
half years. During the year, we recognized in other income $417 million after-tax, consisting of $200 million
in cash and the remainder in commodity inventory, the majority of which was sold by year end. For more
information, see Note 4(cid:178)Inventories and Note 13(cid:178)Contingencies and Commitments, in the Notes to
Consolidated Financial Statements.
Business Environment
Brent crude oil prices averaged over $60 per barrel in the first quarter of 2018, rising to over $70 per barrel in
the second and third quarters of 2018, before falling to the $50 per barrel range at the end of the year. The
energy industry has periodically experienced this type of volatility due to fluctuating supply-and-demand
conditions. 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 disciplined financial and operational priorities that underpin our value proposition.
Operational and Financial Factors Affecting Profitability
The focus areas we believe will drive our success through the price cycles include:
(cid:120) 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 greenhouse gas emission
36
intensity by 2030. Our sustainability efforts continued through 2018 with a focus on advancing our
action plans for climate change, biodiversity, water and human rights. In December 2018, we became
a Founding Member of the Climate Leadership Council (CLC), an international policy institute
founded in collaboration with business and environmental interests to develop a carbon dividend plan.
Participation in the CLC provides another opportunity for ongoing dialogue about carbon pricing and
framing the issues in alignment with our public policy principles. We also belong to and fund
Americans For Carbon Dividends, the education and advocacy branch of the CLC. We are committed
to building a learning organization using human performance principles as we relentlessly pursue
improved Health, Safety and Environment and operational performance.
(cid:120) Focus on financial returns. This is a core aspect of our value proposition. Our goal is to achieve
strong financial returns by controlling our costs, exercising capital discipline and continually
optimizing our portfolio.
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 2018, our production and operating expenses were
relatively flat to 2017.
o Maintain capital 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 diverse,
low cost of supply, programs in our resource base. Our cash allocation priorities call for the
investment of sufficient capital to maintain production and pay the existing dividend.
Additional allocations of capital toward growth projects will be dependent on satisfaction of
other financial priorities. In setting our capital plans, we exercise a disciplined approach that
evaluates projects on a cost of supply basis and is focused on value maximization and cash
flow expansion.
In December 2018, we announced a 2019 capital budget of $6.1 billion, including $3.8 billion
of sustaining capital to maintain existing production levels, and $2.3 billion to grow
production via short-cycle unconventional programs, future major projects and exploration
activities.
o Optimize our portfolio. We continue to optimize our asset portfolio by focusing on low cost
of supply assets that support our strategy. In 2018, we continued to dispose of or market
certain noncore assets and made two acquisitions in Alaska to enhance our existing legacy
asset position. We will continue to evaluate our assets to determine whether they fit our
strategic direction and will optimize the portfolio as necessary, directing our capital
investments to areas that align with our objectives.
(cid:120) Maintain financial strength. We believe financial strength is critical in a cyclical business such as
ours. In 2018, we reduced our debt by $4.7 billion to $15.0 billion at year end, achieving our debt
(cid:85)(cid:72)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:87)(cid:68)(cid:85)(cid:74)(cid:72)(cid:87)(cid:3)(cid:20)(cid:27)(cid:3)(cid:80)(cid:82)(cid:81)(cid:87)(cid:75)(cid:86)(cid:3)(cid:68)(cid:75)(cid:72)(cid:68)(cid:71)(cid:3)(cid:82)(cid:73)(cid:3)(cid:83)(cid:79)(cid:68)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:72)(cid:71)(cid:3)(cid:70)(cid:85)(cid:72)(cid:71)(cid:76)(cid:87)(cid:3)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:88)(cid:83)(cid:74)(cid:85)(cid:68)(cid:71)(cid:72)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:41)(cid:76)(cid:87)(cid:70)(cid:75)(cid:15)(cid:3)(cid:48)(cid:82)(cid:82)(cid:71)(cid:92)(cid:182)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:3)(cid:9)(cid:3)(cid:51)(cid:82)(cid:82)(cid:85)(cid:182)(cid:86). We expect to retire outstanding debt as it matures and exercise flexibility in
paying down our other debt instruments.
37
(cid:120) Return capital to shareholders. In 2018, we paid dividends on our common stock of approximately
$1.4 billion and repurchased $3 billion of our common stock, representing 34 percent of our cash
provided by operating activities. We believe in delivering value to our shareholders through the price
cycles. As a result, we set a priority to increase our dividend rate annually and consistently repurchase
shares on a dollar cost average basis. Since we initiated our current share repurchase program in late
2016, we have bought back $6 billion of shares, with $9 billion remaining on our existing
authorization. Our 2018 dividends, share repurchases, and capital program were fully funded with
cash provided by operating activities.
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. In
October 2018, we announced a dividend increase for the second time this year, an additional
7 percent, resulting in a quarterly dividend rate of $0.305 per share.
In addition to the $6 billion of shares repurchased in 2016 through the end of 2018, in July 2018 we
announced the authorization of an additional $9 billion share repurchases. We expect to execute
$3 billion of this $9 billion share repurchase program in 2019. Whether we undertake these additional
repurchases is ultimately subject to numerous considerations, including market conditions and other
factors. See Risk Factors (cid:179)(cid:50)(cid:88)(cid:85) ability to declare and pay dividends and repurchase shares is subject to
certain (cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:180)
(cid:120) Add to our proved reserve base. We primarily add to our proved reserve base in two 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.
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 2018, our reserve replacement, which included a net increase of 0.2 billion BOE from
sales and purchases, was 147 percent. Increased crude oil reserves accounted for over 90 percent of
the total change in reserves. Our organic reserve replacement, which excludes the impact of sales and
purchases, was 109 percent in 2018. Approximately 33 percent of organic reserve additions are from
Lower 48 unconventional assets, 29 percent from Alaska and 22 percent from Asia Pacific and Middle
East.
In the five years ended December 31, 2018, our reserve replacement was negative 30 percent,
reflecting the impact of asset dispositions and lower prices during that period. Our organic reserve
replacement during the five years ended December 31, 2018, which excludes a decrease of 2.1 billion
MMBOE related to sales and purchases, was 44 percent, reflecting development activities as well as
lower prices during that period.
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.
(cid:120) 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 we are evolving our technical
approach to optimally apply best practices. Companywide, we continue to evaluate potential solutions
to leverage knowledge of technological successes across our operations. Such innovations enhance
38
our ability to economically convert additional resources to reserves, achieve greater operating
efficiencies and reduce our environmental impact.
(cid:120) Develop and retain a talented work force. We strive to attract, train, develop and retain individuals
with the knowledge and skills to implement our business strategy and who support our values and
ethics. To this end, we offer university internships across multiple disciplines to attract the best talent
and, as needed, recruit experienced hires to maintain a broad range of skills 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:
(cid:120) 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
Organization of Petroleum Exporting Countries (OPEC), environmental laws, tax regulations,
governmental policies and weather-related disruptions. The following graph depicts the average
benchmark prices for WTI crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:
Brent crude oil prices averaged $71.04 per barrel in 2018, an increase of 31 percent compared with
$54.27 per barrel in 2017. Similarly, WTI crude oil prices increased 28 percent from $50.90 per
barrel in 2017 to $64.92 per barrel in the same period of 2018. Crude oil prices improved year over
year due to slower growth in global oil production and robust growth in global oil demand. Oil price
volatility escalated in the fourth quarter of 2018 due to geopolitics and concerns about future
economic growth.
Henry Hub natural gas price averages were relatively unchanged, at $3.09 per million British thermal
units (MMBTU) in 2018 compared with $3.11 per MMBTU in 2017. Despite record high natural gas
production, prices remained relatively flat year over year as relatively low inventories and strong
demand offset production growth.
Our realized natural gas liquids prices averaged $30.48 per barrel in 2018, an increase of 21 percent
compared with $25.22 per barrel in 2017, in line with marker movements.
39
The Western Canada Select (WCS) differential to WTI at Hardisty weakened by $14 per barrel in
2018 relative to 2017 due to a lack of pipeline egress coupled with increasing supply from western
Canada. The weaker WCS differential offset year-over-year gains in WTI, resulting in the WCS price
at Hardisty remaining flat in 2018 compared with 2017 at $39 per barrel. 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 realized
bitumen price was $22.29 per barrel in 2018, a decrease of 2 percent compared with $22.66 per barrel
in 2017.
Our worldwide annual average realized price was $53.88 per barrel of oil equivalent (BOE) in 2018,
an increase of 37 percent compared with $39.19 per BOE in 2017. The improvement reflects stronger
marker prices, as well as a shift in our portfolio toward a higher mix of crude oil and less of bitumen
and natural gas.
North (cid:36)(cid:80)(cid:72)(cid:85)(cid:76)(cid:70)(cid:68)(cid:182)(cid:86) 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 United States. 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; delay of plans to develop areas
such as unconventional fields; and underutilization of LNG regasification facilities. Should one or
more of these events occur, our revenues would be reduced and additional asset impairments might be
possible.
(cid:120)
Impairments. We participate in a capital intensive industry. At times, our properties, plants and
equipment 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. For additional information on our impairments in 2018, 2017 and 2016, see Note 9(cid:178)
Impairments, in the Notes to Consolidated Financial Statements.
(cid:120) Effective tax rate. Our operations are located 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 (cid:179)(cid:80)(cid:76)(cid:91)(cid:180)(cid:3)(cid:82)(cid:73)(cid:3)(cid:69)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)-tax earnings
within our global operations.
(cid:120) 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 United States.
Civil unrest or strained relationships with governments may impact our operations or investments.
These changing environments could negatively impact our results of operations, and further changes
to increase government fiscal take could have a negative impact on future operations. Our assets in
Venezuela were expropriated in 2007. Our production operations in Libya and related oil exports
were suspended or significantly curtailed periodically over the last several years due to the closure of
the Es Sider crude oil export terminal. In 2016, the U.K. government enacted tax legislation which
reduced our U.K. corporate tax rate by 10 percent.
We applied the guidance in Staff Accounting Bulletin (SAB) 118 when accounting for the enactment-
date effects of the Tax Cuts and Jobs Act (Tax Legislation) in 2017 and throughout 2018. At
December 31, 2017, our assessment was ongoing for the enactment-date income tax effects of the Tax
40
Legislation under Financial Accounting Standards Board (FASB) Accounting Standards Codification
(cid:11)(cid:36)(cid:54)(cid:38)(cid:12)(cid:3)(cid:55)(cid:82)(cid:83)(cid:76)(cid:70)(cid:3)(cid:26)(cid:23)(cid:19)(cid:15)(cid:3)(cid:179)(cid:44)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:55)(cid:68)(cid:91)(cid:72)(cid:86)(cid:15)(cid:180)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:73)(cid:82)(cid:79)(cid:79)(cid:82)(cid:90)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:86)(cid:83)(cid:72)(cid:70)(cid:87)(cid:86)(cid:29)(cid:3)(cid:85)(cid:72)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:71)(cid:72)(cid:73)(cid:72)(cid:85)(cid:85)(cid:72)(cid:71)(cid:3)(cid:87)(cid:68)(cid:91)(cid:3)(cid:68)(cid:86)(cid:86)(cid:72)(cid:87)(cid:86)(cid:3)
and liabilities, one-time transition tax, and tax on global intangible low-taxed income. As of
December 31, 2018, we have now completed our assessment of the enactment-date income tax effects
of the Tax Legislation. During 2018, we recognized adjustments of $10 million to the provisional tax
benefit amount of $852 million recorded at December 31, 2017, and included these adjustments as a
component of income tax expense. While we still anticipate the Tax Legislation will provide a
positive impact to our U.S. operations in the future primarily because of the reduced U.S. federal
statutory rate, we do not expect to realize cash tax benefits from the Tax Legislation until we move
into a U.S. tax paying position. For additional information, see Note 19(cid:178)Income Taxes, in the Notes
to Consolidated Financial Statements.
Our management carefully considers the fiscal and regulatory environment when evaluating projects
or determining the levels and locations of our activity.
Outlook
First-quarter 2019 production is expected to be 1,290 to 1,330 MBOED, reflecting the impacts of a planned
turnaround in Qatar of approximately 15 MBOED and government-mandated production curtailment in
Canada of approximately 10 MBOED. Production is expected to ramp up in the second half of the year, with
full-year 2019 production expected to be 1,300 to 1,350 MBOED. Production guidance for 2019 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 received.
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.
41
RESULTS OF OPERATIONS
Consolidated Results
(cid:36)(cid:3)(cid:86)(cid:88)(cid:80)(cid:80)(cid:68)(cid:85)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:11)(cid:79)(cid:82)(cid:86)(cid:86)(cid:12)(cid:3)(cid:68)(cid:87)(cid:87)(cid:85)(cid:76)(cid:69)(cid:88)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)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
2018 vs. 2017
Millions of Dollars
2018
2017
2016
$
$
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)
319
(2,257)
(935)
394
209
(16)
(1,329)
(3,615)
Net income attributable to ConocoPhillips increased $7,112 million in 2018. The increase was mainly due to:
(cid:120) Higher realized commodity prices on a more liquids-weighted portfolio.
(cid:120) The absence of a combined $2.5 billion after-tax impairment related to the sale of our interests in the
San Juan Basin and the marketing of our Barnett asset, recognized in the second quarter of 2017.
(cid:120) The absence of a $2.4 billion before- and after-tax impairment of our equity investment in Australia
Pacific LNG Pty Ltd (APLNG), recognized in the second quarter of 2017.
(cid:120) Recognition of $774 million after-tax gain on the Clair disposition in the United Kingdom, in the
fourth quarter of 2018.
(cid:120) Lower depreciation, depletion and amortization (DD&A) expense, mainly due to lower unit-of-
production rates from reserve revisions and disposition impacts.
(cid:120) Recognition of $417 million after-tax in other income from a settlement agreement with PDVSA in
2018.
(cid:120) Lower exploration expenses, primarily due to the absence of first quarter 2017 charges in our Lower
48 and Other International segments.
(cid:120) Lower interest and debt expense because of a lower debt balance.
(cid:120) Higher equity earnings in Qatar Liquefied Gas Company Limited (3) (QG3) and APLNG, primarily
due to higher realized LNG prices, partly offset by the absence of volumes in 2018 related to the
disposition of our interest in the FCCL Partnership in Canada in 2017.
These increases in net income were partly offset by:
(cid:120) The absence of $1.6 billion in after-tax gains related to the sale of certain Canadian assets in 2017.
(cid:120) The absence of a $996 million deferred tax benefit related to the disposition of certain Canadian
assets, recognized in the first quarter of 2017.
(cid:120) The absence of deferred tax benefits totaling $852 million related to the Tax Legislation enacted on
December 22, 2017.
(cid:120) An unrealized loss of $437 million on our Cenovus Energy common shares in 2018.
(cid:120) The absence of a $337 million after-tax award, including interest, from an arbitration settlement with
The Republic of Ecuador in 2017.
42
2017 vs. 2016
Loss attributable to ConocoPhillips decreased $2,760 million in 2017. The decrease was mainly due to:
(cid:120) Higher commodity prices.
(cid:120) Lower DD&A expense, mainly due to lower unit-of-production rates from reserve revisions and
disposition impacts.
(cid:120) Higher gains on dispositions, primarily due to a $1.6 billion after-tax gain in 2017 on the sale of
certain Canadian assets.
(cid:120) Recognition of deferred tax benefits totaling $996 million, primarily related to the disposition of
certain Canadian assets.
(cid:120) Recognition of deferred tax benefits totaling $852 million related to the Tax Legislation enacted on
(cid:120)
December 22, 2017.
Improved equity earnings, mainly due to higher realized prices, lower DD&A from asset disposition
impacts, and the absence of a 2016 deferred tax charge of $174 million resulting from the change of
the tax functional currency for APLNG to the U.S. dollar. These increases were partly offset by lower
volumes from the disposition of our interest in the FCCL Partnership.
(cid:120) Lower exploration expenses mainly due to reduced leasehold impairment expense, dry hole costs and
other exploration expenses.
(cid:120) A $337 million after-tax award, including interest, from an arbitration settlement with The Republic of
Ecuador.
(cid:120) Lower production and operating expenses, primarily due to asset disposition impacts.
(cid:120) Lower net interest expense, primarily due to impacts from the fair market value method of
apportioning interest expense in the United States and reduced debt.
The reduction in loss was partly offset by:
(cid:120) Higher proved property and equity investment impairments, including a combined $2.5 billion after-
tax impairment related to the sale of our interests in the San Juan Basin and the marketing of the
Barnett, as well as a $2.4 billion before- and after-tax impairment of our equity investment in APLNG.
(cid:120) Lower volumes primarily due to asset dispositions in our Lower 48, Asia Pacific and Middle East, and
Canada segments, as well as normal field decline.
(cid:120) A $238 million after-tax charge associated with our early retirements of debt in 2017.
Income Statement Analysis
2018 vs. 2017
Sales and other operating revenues increased 25 percent in 2018, due to higher realized commodity prices,
mainly crude oil, on a portfolio with a higher mix of crude oil and less of bitumen and natural gas. Partly
offsetting this increase, were lower natural gas volumes sold due to 2017 dispositions in the Lower 48 and
Canada.
Equity in earnings of affiliates increased $302 million in 2018. The increase in equity earnings was primarily
due to higher earnings from QG3 and APLNG as a result of higher LNG prices for both affiliates and higher
oil prices in QG3. Partly offsetting this increase, was the absence of equity in earnings resulting from the
disposition of our investment in the FCCL Partnership in 2017.
Gain on dispositions decreased $1,114 million in 2018. The decrease was primarily due to the absence of a
$2.1 billion before-tax gain on the sale of certain Canadian assets recognized in 2017, partly offset by a
$715 million before-tax gain recognized in the fourth quarter of 2018 on the sale of a ConocoPhillips
subsidiary to BP, which held 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the
United Kingdom. For additional information concerning gain on dispositions, see Note 5(cid:178)Assets Held for
Sale, Sold or Acquired and Other Planned Dispositions, in the Notes to Consolidated Financial Statements.
43
Other income decreased $356 million in 2018, mainly due to a $437 million unrealized loss on our Cenovus
Energy common shares in 2018 and the absence of a $337 million arbitration settlement, including interest,
with The Republic of Ecuador in 2017. Partly offsetting the decrease, was $430 million before-tax from a
settlement agreement with PDVSA in 2018.
For discussion of our Cenovus Energy shares, see Note 7(cid:178)Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements. For discussion of our Ecuador and PDVSA settlements, see Note 13(cid:178)
Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
Purchased commodities increased 15 percent in 2018, mainly due to higher crude oil volumes purchased and
higher crude oil prices.
Production and operating expenses increased 1 percent in 2018, primarily due to costs associated with higher
underlying production volumes as well as higher maintenance and wellwork, largely offset by the absence of
costs resulting from 2017 dispositions in our Canada and Lower 48 segments.
Exploration expenses decreased $565 million in 2018, primarily as a result of lower dry hole costs, leasehold
impairment expense and other exploration expenses.
Dry hole costs were reduced primarily due to the absence of before-tax charges of $288 million for multiple
Shenandoah wells in the deepwater Gulf of Mexico, including wells previously suspended. These charges
were reflected in our Lower 48 segment during 2017.
Leasehold impairment expense was reduced mainly due to the absence of before-tax charges of $51 million for
Shenandoah and $38 million for certain Lower 48 mineral assets, both recognized in 2017.
Other exploration expenses were reduced mainly due to the absence of a $43 million before-tax charge for the
cancellation of our Athena drilling rig contract and other rig stacking costs in our Other International segment
in 2017.
For additional information on leasehold impairments and other exploration expenses, see Note 8(cid:178)Suspended
Wells and Other Exploration Expenses, and Note 9(cid:178)Impairments, in the Notes to Consolidated Financial
Statements.
DD&A decreased $889 million in 2018, mainly due to lower unit-of-production rates from positive reserve
revisions and impacts from the 2017 dispositions in our Canada and Lower 48 segments, partly offset by
increased underlying production volumes.
Impairments decreased $6.6 billion in 2018, mainly due to the absence of 2017 impairments of $3.9 billion
before-tax related to our former interests in the San Juan Basin and the Barnett, both in our Lower 48 segment,
as well as a $2.4 billion before- and after-tax impairment of our equity investment in APLNG. For additional
information, see Note 6(cid:178)Investments, Loans and Long-Term Receivables and Note 9(cid:178)Impairments, in the
Notes to Consolidated Financial Statements.
Taxes other than income taxes increased $239 million in 2018, primarily due to higher production taxes in
Alaska and the Lower 48 corresponding with higher realized commodity prices.
Interest and debt expense decreased $363 million in 2018, primarily due to lower debt balances.
See Note 19(cid:178)Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax provision (benefit) and effective tax rate.
44
2017 vs. 2016
Sales and other operating revenues increased 23 percent in 2017, mainly due to higher realized prices across all
commodities, partly offset by lower sales volumes, primarily in our Lower 48, Asia Pacific and Middle East,
and Canada segments as a result of dispositions.
Equity in earnings of affiliates increased $720 million in 2017. The increase in equity earnings was primarily
due to higher realized commodity prices at QG3, APLNG and FCCL; the absence of a 2016 deferred tax
charge of $174 million resulting from a tax functional currency change; and reduced costs mainly from the
disposition of our interest in the FCCL Partnership. The increase in earnings was partly offset by lower
volumes as a result of our FCCL disposition.
Gain on dispositions increased $1.8 billion in 2017. The increase was primarily due to a before-tax gain of
$2.1 billion on the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority
of our western Canada gas assets. For additional information on gains on dispositions, see Note 5(cid:178)Assets
Held for Sale, Sold or Acquired and Other Planned Dispositions, in the Notes to Consolidated Financial
Statements.
Other income increased $274 million in 2017, mainly due to a $337 million before- and after-tax arbitration
award from The Republic of Ecuador. The increase was partly offset by the absence of a gain of $88 million
from our receipt of mineral properties and active leases from the Greater Northern Iron Ore Properties Trust
and a $76 million before-tax damage claim settlement, both in our Lower 48 segment in 2016.
Purchased commodities increased 25 percent in 2017, mainly due to higher commodity prices and increased
activity.
Selling, general and administrative expenses decreased 10 percent in 2017, primarily due to reduced
restructuring expenses, lower headcount and reduced activity.
Exploration expenses decreased 51 percent in 2017, primarily as a result of lower leasehold impairment
expense, dry hole costs and other exploration expenses.
Leasehold impairment expense was reduced mainly due to the absence of 2016 before-tax charges of
$203 million for our Gibson and Tiber leaseholds. The expense was further reduced by the absence of before-
tax charges of $95 million for our Melmar leasehold and $79 million for various Gulf of Mexico leases after
completion of marketing efforts. The reduction was partly offset by a before-tax charge of $51 million for
Shenandoah in deepwater Gulf of Mexico and a before-tax charge of $38 million for certain mineral assets in
our Lower 48 segment, both in 2017.
Dry hole costs were reduced primarily due to the absence of 2016 before-tax charges in deepwater Gulf of
Mexico of $249 million for our Gibson and Tiber wells, and $128 million for our Melmar well. The absence
of a $256 million before-tax charge in 2016 for two dry holes in Nova Scotia further reduced costs. The
reduction in dry hole costs was partly offset by 2017 before-tax charges of $288 million for multiple wells in
Shenandoah, including wells previously suspended, and $63 million for several wells in the Powder River
Basin.
Other exploration expenses were reduced mainly due to the absence of a $146 million before-tax expense in
2016 related to the cancellation of our final Gulf of Mexico deepwater drillship contract, as well as lower rig
stacking costs in Angola. The decrease in expense was partly offset by a $43 million net before-tax charge in
2017 for the settlement of our drilling rig contract in Angola.
For additional information on leasehold impairments and other exploration expenses, see Note 8(cid:178)Suspended
Wells and Other Exploration Expenses, and Note 9(cid:178)Impairments, in the Notes to Consolidated Financial
Statements.
45
DD&A decreased 24 percent in 2017, mainly due to lower unit-of-production rates from reserve revisions and
disposition impacts in our Canada and Lower 48 segments.
Impairments increased $6.5 billion in 2017. For additional information, see Note 9(cid:178)Impairments, in the
Notes to Consolidated Financial Statements.
Interest and debt expense decreased 12 percent in 2017, primarily due to impacts from the fair market value
method of apportioning interest expense in the United States and reduced debt balances.
Other expenses included before-tax charges of $302 million in 2017 for premiums on early debt retirements.
See Note 19(cid:178)Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax provision (benefit) and effective tax rate.
Summary Operating Statistics
Average Net Production
Crude oil (MBD)(1)
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)(2)
Total Production (MBOED)(3)
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Bitumen (per barrel)
Natural gas (per thousand cubic feet)
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other(4)
Leasehold impairment
Dry holes
2018
2017
2016
653
102
66
2,774
599
111
122
3,270
598
145
183
3,857
1,283
1,377
1,569
Dollars Per Unit
68.13
30.48
22.29
5.65
51.96
25.22
22.66
4.07
40.86
16.68
15.27
3.00
Millions of Dollars
274
56
39
369
368
136
430
934
728
466
718
1,912
$
$
$
(1)Thousands of barrels per day.
(2)Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.
(3)Thousands of barrels of oil equivalent per day.
(4)Certain prior period amounts in 2017 and 2016 have been reclassified to conform to the current-period presentation resulting from the
adoption of ASU No. 2017-07. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements,
for additional information.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on
a worldwide basis. At December 31, 2018, our operations were producing in the United States, Norway, the
United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.
46
2018 vs. 2017
Total production, including Libya, of 1,283 MBOED decreased 7 percent in 2018 compared with 2017,
primarily due to:
(cid:120) Disposition impacts from asset sales in Canada and the Lower 48 in 2017.
(cid:120) Normal field decline.
(cid:120) Higher unplanned downtime, including a third-party pipeline outage in Malaysia in 2018.
The decrease in production during 2018 was partly offset by:
(cid:120) New wells online, primarily from tight oil plays in the Lower 48 and Malikai in Malaysia.
(cid:120)
(cid:120) The continued rampup in Libya.
Improved drilling and well performance in Alaska, Norway, Lower 48 and China.
Production excluding Libya was 1,242 MBOED in 2018 compared with 1,356 MBOED in 2017. The volume
from closed dispositions was approximately 200 MBOED in 2017 and 15 MBOED in 2018. The volume from
acquisitions was less than 10 MBOED in 2018. Our underlying production, which excludes the full-year
impact of acquisitions, dispositions, and Libya, increased over 5 percent in 2018 compared with 2017.
2017 vs. 2016
Total production, including Libya, of 1,377 MBOED decreased 12 percent in 2017 compared with 2016,
primarily due to:
(cid:120) Reductions from noncore asset dispositions, including Canada and the Lower 48 in 2017 and the sale
of our interest in the Block B production sharing contract in Indonesia in 2016.
(cid:120) Normal field decline.
The decrease in production during 2017 was partly offset by:
(cid:120) Production from major developments, including tight oil plays in the Lower 48; Malikai and the
Kebabangan gas field in Malaysia; Surmont in Canada; and APLNG in Australia.
Improved drilling and well performance in Alaska, Norway and China.
(cid:120)
Excluding Libya, our 2017 production was 1,356 MBOED. Adjusted for the impact of closed and planned
dispositions of 191 MBOED in 2017 and 434 MBOED in 2016 and Libya, our underlying production
increased 32 MBOED, or 3 percent, compared with 2016.
47
Alaska
Net Income Attributable to ConocoPhillips (millions of dollars) $
1,814
1,466
2018
2017
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per barrel)
Natural gas (per thousand cubic feet)
2016
319
163
12
25
179
171
14
6
186
167
14
7
182
$
70.86
2.48
53.33
2.72
41.93
5.22
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and
natural gas. In 2018, Alaska contributed 23 percent of our worldwide liquids production and less than
1 percent of our natural gas production.
2018 vs. 2017
Alaska reported earnings of $1,814 million in 2018, compared with earnings of $1,466 million in 2017. The
increase in earnings was mainly due to higher realized crude oil prices. Additionally, earnings were improved
due to the absence of a $110 million after-tax impairment related to our small interest in the Point Thomson
Unit, recognized in the first quarter of 2017; a $98 million reduction in tax valuation allowance, recognized in
the fourth quarter of 2018; lower DD&A expense from reserve additions; and a $79 million after-tax benefit
resulting from an accrual reduction due to a transportation cost ruling by the Federal Energy Regulatory
Commission (FERC), recorded in the first quarter of 2018. Partly offsetting these increases in earnings, was
the absence of an $892 million tax benefit from the revaluation of allocated U.S. deferred taxes at a lower
federal statutory rate, in accordance with the Tax Legislation enacted in 2017.
Average production increased 2 percent in 2018 compared with 2017, primarily due to improved drilling and
well performance, 8 MBOED from acquisitions in the Western North Slope and the Greater Kuparuk Area,
and the startup of GMT-1 in the fourth quarter of 2018, partly offset by normal field decline.
Acquisitions
During the second quarter of 2018, we obtained regulatory approvals and completed a transaction with
Anadarko Petroleum Corporation to acquire its 22 percent nonoperated interest in the Western North Slope of
Alaska, as well as its interest in the Alpine Transportation Pipeline, for $386 million, after customary
adjustments. In 2018, our Alaska segment net production included 7 MBOED associated with the additional
interest acquired. In addition, we now have 100 percent interest in approximately 1.2 million acres of
exploration and development lands, including the Willow Discovery.
In December of 2018, we completed a transaction with BP to acquire their nonoperated interest in the Kuparuk
Assets in Alaska, and to sell a ConocoPhillips subsidiary to BP, which held 16.5 percent of our 24 percent
interest in the BP-operated Clair Field in the United Kingdom. In 2018, our Alaska segment net production
included 1 MBOED related to the additional interest acquired in the Greater Kuparuk Area. See Note 5(cid:178)
Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes to Consolidated Financial
Statements, for additional information.
48
2017 vs. 2016
Alaska reported earnings of $1,466 million in 2017, compared with earnings of $319 million in 2016. The
increase in earnings was mainly due to an $892 million tax benefit from the revaluation of allocated U.S.
deferred taxes at a lower federal statutory rate, in accordance with the Tax Legislation. Earnings were
additionally improved due to higher crude oil prices in 2017. The earnings increase was partly offset by a
$110 million after-tax impairment charge for the associated properties, plants and equipment of our small
interest in the Point Thomson unit.
Average production increased 2 percent in 2017 compared with 2016, as the impact of normal field decline
was more than offset by well performance in the Western North Slope, Greater Prudhoe and Greater Kuparuk
areas and lower unplanned downtime.
Lower 48
Net Income (Loss) Attributable to ConocoPhillips (millions of
dollars)
$
1,747
(2,371)
(2,257)
2018
2017
2016
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Natural gas (per thousand cubic feet)
229
69
596
397
180
69
898
399
$
62.99
27.30
2.82
47.36
22.20
2.73
195
88
1,219
486
37.49
14.34
2.20
The Lower 48 segment consists of operations located in the contiguous United States and the Gulf of Mexico.
During 2018, the Lower 48 contributed 36 percent of our worldwide liquids production and 21 percent of our
natural gas production.
2018 vs. 2017
Lower 48 reported earnings of $1,747 million in 2018, compared with a net loss of $2,371 million in 2017.
Earnings increased primarily due to the absence of a combined $2.5 billion after-tax impairment related to the
sale of our interests in the San Juan Basin and the marketing of our Barnett asset, recognized in the second
quarter of 2017; higher realized crude oil and NGL prices; higher crude oil sales volumes; lower DD&A
expense, primarily due to reserve additions and asset disposition impacts, partly offset by higher underlying
volumes; lower exploration expenses and higher gain on dispositions related to noncore asset sales. The
increase in earnings was partly offset by lower natural gas sales volumes, primarily due to the disposition of
our interests in the San Juan Basin in 2017.
In 2018, our average realized crude oil price of $62.99 per barrel was 3 percent less than WTI of $64.92 per
barrel. The differential was driven primarily by local market dynamics in the Gulf Coast, Bakken and Permian
Basin.
49
Total average production decreased 1 percent in 2018 compared with 2017. The decrease was mainly
attributable to normal field decline and disposition impacts related to interests sold in the San Juan Basin and
other noncore assets. Adjusted for the impact of dispositions of 82 MBOED in 2017, underlying production
increased approximately 25 percent in 2018 compared with 2017, primarily due to new production from
unconventional assets in the Eagle Ford, Bakken and Permian Basin.
Asset Dispositions and Other Planned Disposition
In the first quarter of 2018, we completed the sale of certain properties in the Lower 48 segment for net
proceeds of $112 million. No gain or loss was recognized on the sale. In the second quarter of 2018, we
completed the sale of a package of largely undeveloped acreage for net proceeds of $105 million. No gain or
loss was recognized on the sale. In the third quarter of 2018, we completed a noncash exchange of
undeveloped acreage in the Lower 48 segment. This transaction was recorded at fair value resulting in the
recognition of a $44 million after-tax gain. In the fourth quarter of 2018, we sold several packages of
undeveloped acreage in the Lower 48 segment for total net proceeds of $162 million and recognized gains of
approximately $140 million.
In the fourth quarter of 2018, we completed the sale of our interests in the Barnett to Lime Rock Resources for
$196 million after customary adjustments. Production associated with the Barnett averaged 8 MBOED in
2018, of which approximately 55 percent was natural gas and 45 percent was natural gas liquids. After-tax
impairment charges of $69 million were recognized during 2018.
In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in Golden Pass LNG
Terminal and Golden Pass Pipeline located adjacent to the Sabine-Neches Industrial Ship Channel northwest
of Sabine Pass, Texas. The terminal and pipeline capacity was held for receipt, storage and regasification of
LNG purchased from QG3. As a result of entering into these agreements, we expect to recognize a loss of
approximately $60 million in the first quarter of 2019. We have also entered into agreements to amend our
contractual obligations for remaining use of the facilities. Completion of the sale is subject to regulatory
approval.
See Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes to
Consolidated Financial Statements, for additional information.
Acquisition
We began acquiring early life-cycle acreage in the Austin Chalk in the fourth quarter of 2017 and have
accumulated approximately 225,000 net acres at less than $1,000 per acre. We spud our first Austin Chalk
well in late 2018 and plan to drill additional wells in 2019.
2017 vs. 2016
Lower 48 reported a loss of $2,371 million after-tax in 2017, compared with a loss of $2,257 million after-tax
in 2016. The increase in loss was primarily due to proved property impairments in 2017, totaling $2.5 billion
after-tax, for our interests in the San Juan Basin and the Barnett which were written down to fair value less
costs to sell. Lower natural gas, crude oil and natural gas liquids sales volumes from asset dispositions and
normal field decline further increased losses during the year.
50
The increase in losses was partly offset by:
(cid:120) Lower DD&A expense, mainly resulting from a lower unit-of-production rate from reserve revisions,
disposition impacts and lower volumes.
(cid:120) A $689 million tax benefit, primarily related to the revaluation of allocated U.S. deferred taxes at a
lower federal statutory rate, in accordance with the Tax Legislation enacted in 2017.
(cid:120) Higher realized crude oil, natural gas liquids and natural gas prices.
(cid:120) Lower exploration expenses mainly due to:
o Lower leasehold impairment expense, primarily the absence of 2016 after-tax charges of
$132 million for our Gibson and Tiber leaseholds; $62 million for our Melmar leasehold and
$52 million for various Gulf of Mexico leases after completion of marketing efforts. The
reduction was partly offset by an after-tax charge of $33 million for Shenandoah in deepwater
Gulf of Mexico and an after-tax charge of $24 million for certain mineral assets, both in 2017.
o Lower other exploration expenses, mainly due to the absence of a $95 million after-tax
expense in 2016 related to the cancellation of our final Gulf of Mexico deepwater drillship
contract.
o Lower dry hole costs primarily due to the absence of 2016 after-tax charges in deepwater
Gulf of Mexico of $162 million for our Gibson and Tiber wells, and $83 million for our
Melmar well, partly offset by 2017 after-tax charges of $187 million for multiple wells in
Shenandoah and $41 million for several wells in the Powder River Basin.
In 2017, our average realized crude oil price of $47.36 per barrel was 7 percent less than WTI of $50.90 per
barrel. The differential is driven primarily by local market dynamics in the Gulf Coast and Bakken.
Total average production decreased 18 percent in 2017 compared with 2016. The decrease was mainly
attributable to normal field decline and the disposition of our interests in the San Juan Basin, partly offset by
new production, primarily from Eagle Ford and Bakken.
Asset Dispositions
On July 31, 2017, we completed the sale of our interests in the San Juan Basin for total proceeds comprised of
$2.5 billion in cash after customary adjustments and a contingent payment of up to $300 million. The six-year
contingent payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly
U.S. Henry Hub price is at or above $3.20 per million British thermal units. During 2018, we recorded gains
on dispositions for these contingent payments of $28 million.
On September 29, 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash
after customary adjustments.
See Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes to
Consolidated Financial Statements, for additional information.
51
Canada
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
63
2,564
(935)
2018
2017
2016
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
1
66
-
66
12
70
3
9
59
63
122
187
165
7
23
35
148
183
524
300
Average Sales Prices
Crude oil (per barrel)
Natural gas liquids (per barrel)
Bitumen (dollars per barrel)*
Consolidated operations
12.91
15.80
Equity affiliates
Total bitumen
15.27
Natural gas (per thousand cubic feet)
1.49
*Average prices for sales of bitumen produced during 2018 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.
21.43
23.83
22.66
1.93
22.29
-
22.29
1.00
43.69
21.51
48.73
43.70
35.25
14.82
$
Our Canadian operations mainly consist of an oil sands development in the Athabasca region of northeastern
Alberta and a liquids-rich unconventional play in western Canada. In 2018, Canada contributed 8 percent of
our worldwide liquids production and less than one percent of our worldwide natural gas production.
2018 vs. 2017
Canada operations reported earnings of $63 million in 2018 compared with $2,564 million in 2017. The
decrease was mainly due to the absence of a $1.6 billion after-tax gain on the sale of our interest in the FCCL
Partnership and western Canada gas assets and an associated $1.0 billion deferred tax benefit, and equity
earnings in the FCCL Partnership. For additional information on the Canada disposition, see Note 5(cid:178)Assets
Held for Sale, Sold or Acquired and Other Planned Dispositions and Note 7(cid:178)Investment in Cenovus Energy,
in the Notes to Consolidated Financial Statements.
Total average production decreased 95 MBOED in 2018 compared with 2017. The production decrease was
primarily due to our 2017 Canada disposition, partly offset by strong well performance at Surmont.
Acquisition
In February 2018, we acquired approximately 34,500 net acres of undeveloped land in the Montney for a net
purchase price of approximately $120 million. The additional acreage is adjacent to our existing position in
the liquids-rich portion of the Montney.
52
2017 vs. 2016
Canada operations reported earnings of $2,564 million in 2017, an increase of $3,499 million compared with
2016. The earnings increase was mainly due to an after-tax gain of $1.6 billion on the sale of certain Canadian
assets, further discussed below, as well as the recognition of $1.0 billion in deferred tax benefits related to the
capital gains component of our disposition and the recognition of previously unrealizable Canadian tax basis.
In addition to the items discussed above, earnings were further increased due to:
(cid:120) Lower DD&A, mainly from disposition impacts.
(cid:120) Lower dry hole costs, mainly due to the absence of 2016 combined after-tax charges in offshore Nova
Scotia of $187 million for our Cheshire and Monterey Jack wells.
(cid:120) Higher realized prices across all commodities.
(cid:120) A $114 million tax benefit related to our prior decision to exit Nova Scotia deepwater exploration.
(cid:120) Lower production and operating expenses.
(cid:120)
Improved equity earnings, as improved prices and reduced DD&A more than offset the volume loss
from our Canada disposition.
The earnings increase was partly offset by additional volume reductions from the disposition of our western
Canada gas assets.
Total average production decreased 45 percent in 2017 compared with 2016. The production decrease was
primarily due to the Canada disposition, partly offset by production rampup at Surmont.
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 Canadian dollars (CAD) for every $1 CAD by which the WCS quarterly average crude price
exceeds $52 CAD per barrel. During 2018, we recorded gains on dispositions for these contingent payments
of $95 million. See Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the
Notes to Consolidated Financial Statements, for additional information.
Europe and North Africa
Net Income Attributable to ConocoPhillips (millions of dollars) $
1,866
2018
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)
Average Sales Prices
Crude oil (dollars per barrel)
Natural gas liquids (per barrel)
Natural gas (per thousand cubic feet)
2017
553
142
8
484
230
2016
394
122
7
460
205
149
8
503
241
$
70.71
36.87
7.65
54.21
34.07
5.70
43.66
22.62
4.71
53
The Europe and North Africa segment consists of operations principally located in the Norwegian and U.K.
sectors of the North Sea, the Norwegian Sea and Libya. In 2018, our Europe and North Africa operations
contributed 19 percent of our worldwide liquids production and 18 percent of our natural gas production.
2018 vs. 2017
Earnings for Europe and North Africa operations of $1,866 million increased $1,313 million in 2018 compared
to 2017. Earnings in 2018 included a $774 million after-tax gain related to the sale of a ConocoPhillips
subsidiary to BP, which held 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the
United Kingdom. Earnings were also improved due to higher realized crude oil and natural gas prices and
lower DD&A expense, primarily due to reserve additions.
Average production increased 5 percent in 2018, compared with 2017. The increase was mainly due to higher
production in Libya and new wells online in Norway and the United Kingdom. These increases in production
were partly offset by normal field decline and the final cessation of production in several producing gas fields
in the Southern North Sea in the third quarter of 2018. Production associated with the Southern North Sea was
22 million cubic feet a day or 4 MBOED in 2018.
Dispositions
In the fourth quarter of 2018, we completed a transaction to sell a ConocoPhillips subsidiary to BP, which held
16.5 percent of our 24 percent interest in the BP-operated Clair Field in the United Kingdom and acquire their
nonoperated interest in the Kuparuk Assets in Alaska. In 2018, our Europe and North Africa segment net
production associated with the disposed 16.5 percent interest in the Clair Field was approximately 5 MBOED.
We recognized a $774 million after-tax gain in the fourth quarter related to this transaction, as discussed
above. See Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes to
Consolidated Financial Statements, for additional information.
We are currently marketing our United Kingdom Business Unit.
2017 vs. 2016
Earnings for Europe and North Africa operations of $553 million increased 40 percent in 2017. The increase
in earnings was primarily due to higher realized crude oil, natural gas and natural gas liquids prices. Earnings
were additionally improved by lower DD&A, mainly due to reserve revisions; a $60 million tax benefit from
the revaluation of allocated U.S. deferred taxes at a lower U.S. federal statutory rate, in accordance with the
Tax Legislation; and a $41 million tax benefit in Norway.
The increase in earnings was partly offset by the absence of a 2016 net deferred tax benefit of $161 million
resulting from a change in the U.K. tax rate and a lower credit to impairment in 2017, compared with 2016,
reflecting the annual updates to ARO on fields at or nearing the end of life which were impaired in prior years.
The earnings improvement was further reduced by a net deferred tax charge of $65 million in the U.K.
resulting from updated assumptions regarding applicable tax rates.
Average production increased 12 percent in 2017, compared with 2016. The increase was mainly due to the
resumption and rampup of production in Libya; improved drilling and well performance in Norway; new
production from the Greater Britannia Area and Norway; and higher Norway gas offtake, partly offset by
normal field decline.
54
Asia Pacific and Middle East
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
2,070
(1,098)
209
2018
2017
2016
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
89
14
103
3
7
10
93
14
107
4
7
11
97
14
111
7
8
15
626
1,031
1,657
687
1,007
1,694
730
899
1,629
Total Production (MBOED)
389
401
399
Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations
Equity affiliates
Total crude oil
Natural gas liquids (dollars per barrel)
Consolidated operations
Equity affiliates
Total natural gas liquids
Natural gas (dollars per thousand cubic feet)
Consolidated operations
Equity affiliates
Total natural gas
$
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
42.23
44.11
42.47
29.00
31.13
30.11
4.31
2.97
3.57
The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste
and Qatar. During 2018, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids
production and 60 percent of our natural gas production.
2018 vs. 2017
Asia Pacific and Middle East reported earnings of $2,070 million in 2018, compared with a loss of
$1,098 million in 2017. The increase in earnings was mainly due to the absence of a $2,384 million before- and
after-tax charge for the impairment of our APLNG investment in 2017, higher realized commodity prices, and
increased equity in earnings of affiliates, mainly due to higher LNG prices. (cid:54)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)Note
6(cid:178)Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for
information on the 2017 impairment of our APLNG investment.
55
Average production decreased 3 percent in 2018, compared with 2017. The decrease was primarily due to
unplanned downtime in Malaysia related to the rupture of a third-party pipeline which carries gas production
from the Kebabangan gas field in Malaysia and normal field decline. This decrease was partly offset by new
wells online at Malakai in Malaysia and an infill drilling program in China.
Asset Disposition
In the fourth quarter of 2018, we entered into an agreement to sell our 30 percent interest in the Greater Sunrise
Fields to the government of Timor-Leste for $350 million, subject to customary adjustments. The transaction is
conditional on the funding approval from the Timor-Leste government as well as regulatory approvals. No
production or reserve impacts are associated with the sale.
2017 vs. 2016
Asia Pacific and Middle East reported a loss of $1,098 million in 2017, compared with earnings of $209 million
in 2016. The increase in loss was mainly due to a $2,384 million before- and after-tax charge for the impairment
of our APLNG investment in 2017. (cid:41)(cid:82)(cid:85)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:3)(cid:76)(cid:80)(cid:83)(cid:68)(cid:76)(cid:85)(cid:80)(cid:72)(cid:81)(cid:87)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:180)(cid:3)
section of Note 6(cid:178)Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial
Statements. Additionally, lower sales volumes in Indonesia, Australia and China further increased losses.
The increase in losses was partly offset by higher equity earnings, mainly as a result of higher commodity prices,
increased sales volumes at APLNG and the absence of a 2016 deferred tax charge of $174 million resulting from
the change of our APLNG tax functional currency. Higher realized crude oil and natural gas prices on non-
equity volumes further reduced the loss.
Average production was essentially flat in 2017.
Other International
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
364
167
(16)
2018
2017
2016
The Other International segment includes exploration activities in Colombia and Chile.
2018 vs. 2017
Other International operations reported earnings of $364 million in 2018, compared with earnings of
$167 million in 2017. The increase in earnings was primarily due to recognizing $417 million after-tax in
other income under a settlement agreement with PDVSA associated with an arbitration award issued by the
ICC. Partly offsetting the increase in earnings, was the absence of a $320 million after-tax award from an
arbitration settlement with The Republic of Ecuador in 2017. See Note 13(cid:178)Contingencies and Commitments
in the Notes to Consolidated Financial Statements, for additional information.
New Country Entrance
We received approval from (cid:36)(cid:85)(cid:74)(cid:72)(cid:81)(cid:87)(cid:76)(cid:81)(cid:68)(cid:182)(cid:86) government in January 2019 for a 50 percent nonoperated interest in
the El Turbio Este block in the Austral Basin.
2017 vs. 2016
Other International operations reported earnings of $167 million in 2017, compared with a loss of $16 million
in 2016. The increase in earnings was primarily due to a $320 million after-tax International Centre for
Settlement of Investment Disputes (ICSID) award from an arbitration with The Republic of Ecuador. Earnings
were additionally increased due to lower rig stacking costs in Angola. The increase in earnings was partly
56
offset by the absence of a $138 million gain in 2016 on the disposition of ConocoPhillips Senegal B.V., the
entity that held our interest in three exploration blocks offshore Senegal, and a $45 million tax charge from the
revaluation of allocated U.S. deferred taxes at a lower U.S. federal statutory rate, in accordance with the Tax
Legislation.
Corporate and Other
Net Loss Attributable to ConocoPhillips
Net interest
Corporate general and administrative expenses
Technology
Other
Millions of Dollars
2018
2017
$
$
(680)
(91)
109
(1,005)
(1,667)
(739)
(193) *
20
(1,224) *
(2,136)
2016
(980)
(147) *
50
(252) *
(1,329)
*Certain amounts have been reclassified to reflect the adoption of ASU No. 2017-07. See Note 2(cid:178)Changes in Accounting Principles, in the
Notes to Consolidated Financial Statements, for additional information.
2018 vs. 2017
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net
interest decreased $59 million in 2018 compared with 2017, primarily due to less interest from lower debt
balances, higher capitalized interest on projects, and an accrual reduction due to a transportation cost ruling by
the FERC in the first quarter of 2018. Partly offsetting these impacts, were reduced tax benefits on interest
expense following the Tax Legislation, which lowered the U.S. corporate income tax rate from 35 percent to
21 percent effective January 1, 2018, and a lower tax benefit due to higher interest from the fair market value
method of apportioning interest expense in the United States.
Corporate general and administrative expenses include compensation programs and staff costs. These costs
decreased by $102 million in 2018 compared with 2017, primarily due to lower staff expenses and costs
associated with certain key employee compensation programs.
Technology includes our investment in new technologies or businesses, as well as licensing revenues.
Activities are focused on tight oil reservoirs, LNG, oil sands and other production operations. Earnings from
Technology increased by $89 million in 2018 compared with 2017, primarily due to higher licensing revenues.
See Note 24(cid:178)Sales and Other Operating Revenues, in the Notes to Consolidated Financial Statements, for
additional information.
The category (cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:180) includes certain foreign currency transaction gains and losses, environmental costs
associated with sites no longer in operation, other costs not directly associated with an operating segment,
premiums incurred on the early retirement of debt, unrealized holding gains or losses on equity securities, and
pension settlement expense. Losses in (cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:180) decreased by $219 million in 2018 compared with 2017,
primarily due to the absence of an $813 million tax charge from the revaluation of deferred taxes at a lower
federal statutory rate, in accordance with the Tax Legislation enacted in 2017; lower premiums on the early
retirement of debt; partly offset by a $437 million unrealized loss on our Cenovus Energy common shares.
57
2017 vs. 2016
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net
interest decreased 25 percent in 2017 compared with 2016, primarily due to impacts from the fair market value
method of apportioning interest expense in the United States and lower interest as a result of reduced debt.
Higher interest income further drove the decrease in net interest, which was partly offset by lower capitalized
interest on projects.
Corporate general and administrative expenses which include pension settlement expenses and compensation
program costs increased $46 million in 2017 compared with 2016, primarily due to higher costs associated
with certain key employee compensation programs and staff expenses. See Note 2(cid:178)Changes in Accounting
Principles, in the Notes to Consolidated Financial Statements, for additional information.
Technology includes our investment in new technologies or businesses, as well as licensing revenues received.
Activities are focused on tight oil reservoirs, LNG, oil sands and other production operations. Earnings from
Technology were $20 million in 2017, compared with $50 million in 2016. The decrease in earnings primarily
resulted from lower licensing revenues, partly offset by reduced technology program spend.
The category (cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:180) 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 and
premiums incurred on the early retirement of debt. Losses in (cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:180) increased $972 million in 2017, mainly
due to an $813 million tax charge from the revaluation of deferred taxes at a lower federal statutory rate, in
accordance with the Tax Legislation and premiums on our early retirement of debt.
58
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
2018
2017
2016
$
12,934
5,915
112
14,968
32,064
32 %
5 %
7,077
6,325
2,575
19,703
30,801
39
5
4,403
3,610
1,089
27,275
35,226
44
9
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 2018, the primary uses of
our available cash were $6,750 million to support our ongoing capital expenditures and investments program;
$4,995 million to reduce debt; $2,999 million to repurchase our common stock; and $1,363 million to pay
dividends on our common stock. During 2018, cash, cash equivalents, and restricted cash decreased by
$385 million to $6,151 million.
We believe current cash balances and cash generated by operations, together with access to external sources of
(cid:73)(cid:88)(cid:81)(cid:71)(cid:86)(cid:3)(cid:68)(cid:86)(cid:3)(cid:71)(cid:72)(cid:86)(cid:70)(cid:85)(cid:76)(cid:69)(cid:72)(cid:71)(cid:3)(cid:69)(cid:72)(cid:79)(cid:82)(cid:90)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:54)(cid:76)(cid:74)(cid:81)(cid:76)(cid:73)(cid:76)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:54)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:90)(cid:76)(cid:79)(cid:79)(cid:3)(cid:69)(cid:72)(cid:3)(cid:86)(cid:88)(cid:73)(cid:73)(cid:76)(cid:70)(cid:76)(cid:72)(cid:81)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:80)(cid:72)(cid:72)(cid:87)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:73)(cid:88)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)
requirements in the near and long term, including our capital spending program, share repurchases, dividend
payments and required debt payments.
Significant Sources of Capital
Operating Activities
During 2018, cash provided by operating activities was $12,934 million, an 83 percent increase from 2017.
The increase was primarily due to higher realized commodity prices and higher distributions from equity
affiliates.
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 natural gas liquids. 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.
The level of absolute production volumes, as well as product and location mix, impacts our cash flows.
Full-year production averaged 1,283 MBOED in 2018. Full-year production excluding Libya averaged
1,242 MBOED in 2018 and is expected to be 1,300 to 1,350 MBOED in 2019. 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.
59
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 2018,
our reserve replacement, which included a net increase of 0.2 billion BOE from sales and purchases, was
147 percent. Increased crude oil reserves accounted for over 90 percent of the total change in reserves. Our
organic reserve replacement, which excludes the impact of sales and purchases, was 109 percent in 2018.
Approximately 33 percent of organic reserve additions are from Lower 48 unconventional assets, 29 percent
from Alaska and 22 percent from Asia Pacific and Middle East.
In the five years ended December 31, 2018, our reserve replacement, which included a decrease of 2.1 billion
BOE from sales and purchases, was negative 30 percent, reflecting the impact of asset dispositions and lower
prices during that period. Our organic reserve replacement during the five years ended December 31, 2018,
was 44 percent, reflecting development activities as well as lower prices during that period.
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
2019 capital budget, see the (cid:179)(cid:21)019 Capital (cid:37)(cid:88)(cid:71)(cid:74)(cid:72)(cid:87)(cid:180) section within (cid:179)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79) Resources and (cid:47)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:76)(cid:87)(cid:92)(cid:180) and for
additional information on proved reserves, including both developed and undeveloped reserves, see the (cid:179)(cid:50)(cid:76)(cid:79)
and Gas (cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180) section of this report.
As discussed in the (cid:179)(cid:38)(cid:85)(cid:76)(cid:87)(cid:76)(cid:70)al Accounting (cid:40)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:86)(cid:180) 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. In 2018 and 2017, revisions
increased reserves, while in 2016, revisions decreased reserves. It is not possible to reliably predict how
revisions will impact reserve quantities in the future.
Investing Activities
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 received $253 million
net proceeds for customary adjustments related to our transaction with BP for the disposition of a
ConocoPhillips subsidiary holding a 16.5 percent interest in the Clair Field in the United Kingdom and the
acquisition of the Kuparuk Assets. We received contingent payments of $95 million in relation to our 2017
Canada disposition to Cenovus Energy.
Proceeds from asset sales in 2017 were $13.9 billion. 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 $11.0 billion in cash after customary adjustments and 208 million
Cenovus Energy common shares. We completed the sale of our interests in the San Juan Basin to an affiliate
of Hilcorp Energy Company. Total proceeds for the sale were $2.5 billion in cash after customary
adjustments. We also completed the sale of our interest in the Panhandle assets for $178 million in cash after
customary adjustments.
For additional information on our dispositions and investment in Cenovus common shares, see Note 5(cid:178)Assets
Held for Sale, Sold or Acquired and Other Planned Dispositions and Note 7(cid:178)Investment in Cenovus Energy,
in the Notes to Consolidated Financial Statements, and the Results of Operations section within (cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)
Discussion and Analysis.
Commercial Paper and Credit Facilities
In May 2018, we refinanced our revolving credit facility from a total aggregate principal amount of
$6.75 billion to $6.0 billion with a new 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
60
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 United States. 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,
2018 or December 31, 2017. We had no direct outstanding borrowings or letters of credit under the revolving
credit facility at December 31, 2018 and December 31, 2017. 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, 2018.
In August 2018, Fitch upgraded our long-term debt rating from (cid:179)(cid:36)-(cid:180)(cid:3)(cid:87)(cid:82)(cid:3)(cid:179)(cid:36)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:76)(cid:85)(cid:3)(cid:82)(cid:88)(cid:87)(cid:79)(cid:82)(cid:82)(cid:78)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
(cid:71)(cid:72)(cid:69)(cid:87)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:179)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:89)(cid:72)(cid:180)(cid:3)(cid:87)(cid:82)(cid:3)(cid:179)(cid:86)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:17)(cid:180)(cid:3)(cid:3)(cid:44)(cid:81)(cid:3)(cid:54)(cid:72)(cid:83)(cid:87)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:15)(cid:3)(cid:48)(cid:82)(cid:82)(cid:71)(cid:92)(cid:182)(cid:86)(cid:3)(cid:44)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:54)(cid:72)(cid:85)(cid:89)(cid:76)(cid:70)(cid:72)(cid:86)(cid:3)(cid:88)(cid:83)(cid:74)(cid:85)(cid:68)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:87)(cid:86)(cid:3)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
long-(cid:87)(cid:72)(cid:85)(cid:80)(cid:3)(cid:71)(cid:72)(cid:69)(cid:87)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:179)(cid:37)(cid:68)(cid:68)(cid:20)(cid:180)(cid:3)(cid:87)(cid:82)(cid:3)(cid:179)(cid:36)(cid:22)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:87)(cid:86)(cid:3)(cid:82)(cid:88)(cid:87)(cid:79)(cid:82)(cid:82)(cid:78)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:71)(cid:72)(cid:69)(cid:87)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:179)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:89)(cid:72)(cid:180)(cid:3)(cid:87)(cid:82)(cid:3)(cid:179)(cid:86)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:17)(cid:180)(cid:3)(cid:3)(cid:44)(cid:81)(cid:3)
(cid:49)(cid:82)(cid:89)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:15)(cid:3)(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:3)(cid:9)(cid:3)(cid:51)(cid:82)(cid:82)(cid:85)(cid:182)(cid:86)(cid:3)(cid:88)(cid:83)(cid:74)(cid:85)(cid:68)(cid:71)(cid:72)(cid:71)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:79)(cid:82)(cid:81)(cid:74)-(cid:87)(cid:72)(cid:85)(cid:80)(cid:3)(cid:71)(cid:72)(cid:69)(cid:87)(cid:3)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:179)(cid:36)-(cid:180)(cid:3)(cid:87)(cid:82)(cid:3)(cid:179)(cid:36)(cid:15)(cid:180)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:3)(cid:86)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)
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
of credit as collateral. At December 31, 2018 and 2017, we had direct bank letters of credit of $323 million
and $338 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 U.S. Securities and Exchange Commission
(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(cid:178)Guarantees, in the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
61
Capital Requirements
(cid:41)(cid:82)(cid:85)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:69)(cid:82)(cid:88)(cid:87)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:71)(cid:76)(cid:87)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)(cid:40)(cid:91)(cid:83)(cid:72)(cid:81)(cid:71)(cid:76)(cid:87)(cid:88)(cid:85)(cid:72)(cid:86)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:17)
Our debt balance at December 31, 2018, was $15.0 billion, a decrease of $4.7 billion from the balance at
December 31, 2017. We achieved our stated debt target of $15 billion eighteen months earlier than the
original target date of year-end 2019.
In 2018, we repaid the $250 million floating rate note due in 2018 at its natural maturity. We also redeemed or
repurchased a total $4,450 million of debt, described below, incurring $208 million in net premiums above
(cid:69)(cid:82)(cid:82)(cid:78)(cid:3)(cid:89)(cid:68)(cid:79)(cid:88)(cid:72)(cid:15)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)ement.
(cid:120) 4.20% Notes due 2021 with remaining principal of $1.0 billion.
(cid:120) 2.875% Notes due 2021 with principal of $750 million.
(cid:120) 2.4% Notes due 2022 with principal of $1.0 billion (partial repurchase of $671 million).
(cid:120) 3.35% Notes due 2024 with principal of $1.0 billion (partial repurchase of $574 million).
(cid:120) 2.2% Notes due 2020 with principal of $500 million.
(cid:120) 3.35% Notes due 2025 with principal of $500 million (partial repurchase of $301 million).
(cid:120) 4.15% Notes due 2034 with principal of $500 million (partial repurchase of $254 million).
(cid:120) 8.125% Notes due 2030 with principal of $600 million (partial repurchase of $210 million).
(cid:120) 7.8% Notes due 2027 with principal of $300 million (partial repurchase of $97 million).
(cid:120) 7.9% Notes due 2047 with principal of $100 million (partial repurchase of $40 million).
(cid:120) 9.125% Notes due 2021 with principal of $150 million (partial repurchase of $27 million).
(cid:120) 8.20% Notes due 2025 with principal of $150 million (partial repurchase of $16 million).
(cid:120) 7.65% Notes due 2023 with principal of $88 million (partial repurchase of $10 million).
For more information on Debt, see Note 11(cid:178)Debt, in the Notes to Consolidated Financial Statements.
On February 1, 2018, we announced an increase in the quarterly dividend to $0.285 per share, compared with
the previous quarterly dividend of $0.265 per share. The dividend was paid on March 1, 2018, to stockholders
of record at the close of business on February 12, 2018. On May 4, 2018, we announced a quarterly dividend
of $0.285 per share. The dividend was paid on June 1, 2018, to stockholders of record at the close of business
on May 14, 2018. On July 11, 2018, we announced a quarterly dividend of $0.285 per share. The dividend
was paid on September 4, 2018, to stockholders of record at the close of business on July 23, 2018. On
October 5, 2018, we announced a 7 percent increase in the quarterly dividend to $0.305 per share. The
dividend was paid on December 3, 2018, to stockholders of record at the close of business on October 15,
2018. On January 30, 2019, we announced a quarterly dividend of $0.305 cents per share, payable March 1,
2019, to stockholders of record at the close of business on February 11, 2019.
In late 2016, we initiated our current share repurchase program. As of June 30, 2018, we had announced
authorization to repurchase a total of $6 billion of our common stock. We repurchased $3 billion in 2017 and
$3 billion in 2018. On July 12, 2018, we announced an authorization of an additional $9 billion in share
repurchases bringing the total program authorization to $15 billion. We expect to execute $3 billion of the
remaining $9 billion of our share repurchase program in 2019. Whether we undertake these additional
repurchases is ultimately subject to numerous considerations, market conditions and other factors. See Risk
(cid:41)(cid:68)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:179)(cid:50)(cid:88)(cid:85)(cid:3)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:71)(cid:72)(cid:70)(cid:79)(cid:68)(cid:85)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:68)(cid:92)(cid:3)(cid:71)(cid:76)(cid:89)(cid:76)(cid:71)(cid:72)(cid:81)(cid:71)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:83)(cid:88)(cid:85)(cid:70)(cid:75)(cid:68)(cid:86)(cid:72)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)(cid:86)(cid:88)(cid:69)(cid:77)(cid:72)(cid:70)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:70)(cid:72)(cid:85)(cid:87)(cid:68)(cid:76)(cid:81)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:180)(cid:3)(cid:3)
Since our share repurchase program began in November 2016, we have repurchased 111 million shares at a
cost of $6.1 billion through December 31, 2018.
During the third quarter of 2017, we made a $600 million contribution to our domestic qualified pension plan,
(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:76)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:68)(cid:86)(cid:75)(cid:3)(cid:41)(cid:79)(cid:82)(cid:90)(cid:86)(cid:3)(cid:41)(cid:85)(cid:82)(cid:80)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:36)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
consolidated statement of cash flows. This additional contribution lowered our domestic pension deficit,
thereby reducing 2018 premiums charged by the Pension Benefit Guaranty Corporation.
62
Contractual Obligations
The table below summarizes our aggregate contractual fixed and variable obligations as of December 31, 2018:
Debt obligations (a)
Capital lease obligations (b)
Total debt
Interest on debt and other obligations
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
14,191
777
14,968
12,213
1,394
9,703
1,519
7,908
178
115
47,998
$
$
Up to 1
Year
33
79
112
865
248
4,000
380
378
20
115
6,118
Years
2(cid:177)3
159
155
314
1,710
561
1,854
634
672
28
(h)
5,773
Years
4(cid:177)5
After
5 Years
987
143
1,130
1,634
373
1,422
505
681
26
(h)
5,771
13,012
400
13,412
8,004
212
2,427
-
6,177
104
(h)
30,336
(a)
Includes $220 million of net unamortized premiums, discounts and debt issuance costs. See Note 11(cid:178)
Debt, in the Notes to Consolidated Financial Statements, for additional information.
(b) Capital lease obligations are presented on a discounted basis.
(c) Operating lease obligations are presented on an undiscounted basis.
(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 $3,412 million.
Purchase obligations of $5,169 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 2019 through 2023. For additional information related to expected benefit payments subsequent to
2023, see Note 18(cid:178)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.
(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.
63
(h) Excludes unrecognized tax benefits of $966 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
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Capital Program
Millions of Dollars
2018
2017
2016
$
$
1,298
3,184
477
877
718
6
190
6,750
815
2,136
202
872
482
21
63
4,591
883
1,262
698
1,020
838
104
64
4,869
Our capital expenditures and investments for the three-year period ended December 31, 2018, totaled
$16.2 billion. The 2018 expenditures supported key exploration and developments, primarily:
(cid:120) Development, appraisal and exploration activities in the Lower 48, including Eagle Ford, Bakken and
Delaware in the Permian Basin.
(cid:120) Leasehold acquisition and exploration, appraisal and development activities in Alaska related to the
Western North Slope; development activities in the Greater Kuparuk Area and the Greater Prudhoe
Area.
(cid:120) Development activities in Europe, including the Greater Ekofisk Area, Clair Ridge and Aasta
Hansteen.
(cid:120) Leasehold acquisition, optimization of oil sands development and appraisal activities in liquids-rich
plays in Canada.
(cid:120) Continued development in China, Australia, Indonesia, and Malaysia, and exploration and appraisal
activities in Malaysia.
2019 CAPITAL BUDGET
In December 2018, we announced a 2019 capital budget of $6.1 billion which includes funding for ongoing
conventional and unconventional development drilling programs, major projects, exploration and appraisal
activities, and base maintenance activities. We are planning to allocate approximately:
(cid:120) 70 percent of our 2019 capital expenditures budget to development drilling programs. These funds
will focus predominantly on the Lower 48 unconventionals including the Eagle Ford, Bakken and
Delaware, as well as development drilling in Alaska, Canada and Europe.
(cid:120) 15 percent of our 2019 capital expenditures budget to maintain base production and corporate
expenditures.
(cid:120) 10 percent of our 2019 capital expenditures budget to major projects. These funds will focus on major
projects in Alaska, China, Australia, Europe and Malaysia.
(cid:120) 5 percent of our 2019 capital expenditures budget to new exploration activity, primarily in Alaska and
the Lower 48.
64
For information on proved undeveloped reserves and the associated costs to develop these reserves, see the
(cid:179)(cid:50)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:68)(cid:86)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:86)ection.
Contingencies
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed
against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the
placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active
and inactive sites. We regularly assess the need for accounting recognition or disclosure of these
contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a
liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be
reasonably estimated and no amount within the range is a better estimate than any other amount, then the
minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party
recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With
respect to income tax related contingencies, we use a cumulative probability-weighted loss accrual in cases
where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to known contingent
liability exposures will exceed current accruals by an amount that would have a material adverse impact on our
consolidated financial statements(cid:17)(cid:3)(cid:3)(cid:41)(cid:82)(cid:85)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:179)(cid:38)(cid:85)(cid:76)(cid:87)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)
(cid:40)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:86)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:3)(cid:20)(cid:22)(cid:178)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, 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(cid:178)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:
(cid:120) U.S. Federal Clean Air Act, which governs air emissions.
(cid:120) U.S. Federal Clean Water Act, which governs discharges to water bodies.
(cid:120) European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals
(REACH).
(cid:120) 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.
(cid:120) U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage
and disposal of solid waste.
65
(cid:120) 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 United States.
(cid:120) 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.
(cid:120) U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground
injection wells.
(cid:120) 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.
(cid:120) 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
(cid:68)(cid:86)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:81)(cid:82)(cid:87)(cid:76)(cid:70)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:83)(cid:72)(cid:85)(cid:76)(cid:82)(cid:71)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:74)(cid:72)(cid:81)(cid:70)(cid:92)(cid:182)(cid:86)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:83)(cid:83)(cid:79)(cid:76)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:17)(cid:3)(cid:3)(cid:48)(cid:68)(cid:81)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)
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
United States and in other countries in which we operate. Notable areas of potential impacts include air
emission compliance and remediation obligations in the United States 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 the U.S.
Environmental Protection Agency (EPA), the U.S. Department of the Interior, 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
66
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, 2018, there were 14 sites around the United States 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
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 $442 million in 2018 and are expected to be about $530 million per year
in 2019 and 2020. Capitalized environmental costs were $191 million in 2018 and are expected to be about
$240 million per year in 2019 and 2020.
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, 2018, our balance sheet included total accrued environmental costs of $178 million,
compared with $180 million at December 31, 2017, 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.
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 greenhouse gas (GHG) reduction.
67
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:
(cid:120) European Emissions Trading Scheme (ETS), the program through which many of the European Union
(EU) member states are implementing the Kyoto Protocol. Our cost of compliance with the EU ETS
in 2018 was approximately $5.6 million (net share before-tax).
(cid:120) 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 2018 was approximately
$4 million.
(cid:120) The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007),
(cid:70)(cid:82)(cid:81)(cid:73)(cid:76)(cid:85)(cid:80)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:40)(cid:51)(cid:36)(cid:3)(cid:75)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:88)(cid:87)(cid:75)(cid:82)(cid:85)(cid:76)(cid:87)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:85)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:72)(cid:3)(cid:70)(cid:68)(cid:85)(cid:69)(cid:82)(cid:81)(cid:3)(cid:71)(cid:76)(cid:82)(cid:91)(cid:76)(cid:71)(cid:72)(cid:3)(cid:68)(cid:86)(cid:3)(cid:68)(cid:81)(cid:3)(cid:179)(cid:68)(cid:76)(cid:85)(cid:3)(cid:83)(cid:82)(cid:79)(cid:79)(cid:88)(cid:87)(cid:68)(cid:81)(cid:87)(cid:180)(cid:3)(cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)
Federal Clean Air Act.
(cid:120) (cid:55)(cid:75)(cid:72)(cid:3)(cid:56)(cid:17)(cid:54)(cid:17)(cid:3)(cid:40)(cid:51)(cid:36)(cid:182)(cid:86)(cid:3)(cid:68)(cid:81)(cid:81)(cid:82)(cid:88)(cid:81)(cid:70)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:48)(cid:68)(cid:85)(cid:70)(cid:75)(cid:3)(cid:21)(cid:28)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:19)(cid:3)(cid:11)(cid:83)(cid:88)(cid:69)(cid:79)(cid:76)(cid:86)(cid:75)(cid:72)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:179)(cid:44)(cid:81)(cid:87)(cid:72)(cid:85)(cid:83)(cid:85)(cid:72)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:53)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)
(cid:39)(cid:72)(cid:87)(cid:72)(cid:85)(cid:80)(cid:76)(cid:81)(cid:72)(cid:3)(cid:51)(cid:82)(cid:79)(cid:79)(cid:88)(cid:87)(cid:68)(cid:81)(cid:87)(cid:86)(cid:3)(cid:38)(cid:82)(cid:89)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:38)(cid:79)(cid:72)(cid:68)(cid:81)(cid:3)(cid:36)(cid:76)(cid:85)(cid:3)(cid:36)(cid:70)(cid:87)(cid:3)(cid:51)(cid:72)(cid:85)(cid:80)(cid:76)(cid:87)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:51)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:86)(cid:15)(cid:180)(cid:3)(cid:26)(cid:24)(cid:3)(cid:41)(cid:72)(cid:71)(cid:17)(cid:3)(cid:53)(cid:72)(cid:74)(cid:17)(cid:3)(cid:20)(cid:26)(cid:19)(cid:19)(cid:23)(cid:3)(cid:11)(cid:36)(cid:83)(cid:85)(cid:76)(cid:79)(cid:3)(cid:21)(cid:15)(cid:3)
(cid:21)(cid:19)(cid:20)(cid:19)(cid:12)(cid:12)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:40)(cid:51)(cid:36)(cid:182)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:56)(cid:17)(cid:54)(cid:17)(cid:3)(cid:39)(cid:72)(cid:83)(cid:68)(cid:85)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:55)(cid:85)(cid:68)(cid:81)(cid:86)(cid:83)(cid:82)(cid:85)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:182)(cid:86)(cid:3)(cid:77)(cid:82)(cid:76)(cid:81)(cid:87)(cid:3)(cid:83)(cid:85)(cid:82)(cid:80)(cid:88)(cid:79)(cid:74)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:79)(cid:3)(cid:53)(cid:88)(cid:79)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)
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.
(cid:120) (cid:55)(cid:75)(cid:72)(cid:3)(cid:56)(cid:17)(cid:54)(cid:17)(cid:3)(cid:40)(cid:51)(cid:36)(cid:182)(cid:86)(cid:3)(cid:68)(cid:81)(cid:81)(cid:82)(cid:88)(cid:81)(cid:70)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:20)(cid:23)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:24)(cid:15)(cid:3)(cid:82)(cid:88)(cid:87)(cid:79)(cid:76)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:3)(cid:86)(cid:72)(cid:85)(cid:76)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:86)(cid:87)(cid:72)(cid:83)(cid:86)(cid:3)(cid:76)(cid:87)(cid:3)(cid:83)(cid:79)(cid:68)(cid:81)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:68)(cid:78)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)
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.
(cid:120) Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon tax legislation
in 2018 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 $0.6 million (net share before-tax).
(cid:120) 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 United States announced its intention to withdraw from the Paris Agreement,
there is no guarantee that the commitments made by the United States will not be implemented, in
whole or in part, by U.S. state and local governments or by major corporations headquartered in the
United States.
In the United States, 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:
(cid:120) Whether and to what extent legislation or regulation is enacted.
(cid:120) The timing of the introduction of such legislation or regulation.
(cid:120) The nature of the legislation (such as a cap and trade system or a tax on emissions) or regulation.
(cid:120) The price placed on GHG emissions (either by the market or through a tax).
68
(cid:120) The GHG reductions required.
(cid:120) The price and availability of offsets.
(cid:120) The amount and allocation of allowances.
(cid:120) Technological and scientific developments leading to new products or services.
(cid:120) Any potential significant physical effects of climate change (such as increased severe weather events,
changes in sea levels and changes in temperature).
(cid:120) 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 Practice
covering the assessment and registering of significant and high sustainable development risks based on their
consequence and likelihood of occurrence. A corporate Climate Change Action Plan has been developed to
track 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:
(cid:120) GHG-related legislation and regulation.
(cid:120) GHG emissions management.
(cid:120) Physical climate-related impacts.
(cid:120) Climate-related disclosure and reporting.
The company uses a range of estimated future costs of GHG emissions for internal planning purposes,
including an estimated market cost of GHG emissions of $40 per metric tonne applied beginning in the year
2024 to evaluate certain future projects and opportunities. 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 Climate Leadership Council (CLC), an international
policy institute founded in collaboration with business and environmental interests to develop a carbon
dividend plan. Participation in the CLC provides another opportunity for ongoing dialogue about carbon
pricing and framing the issues in alignment with our public policy principles. We also belong to and fund
Americans For Carbon Dividends, the education and advocacy branch of the CLC.
In 2017 and 2018, cities, counties, a state government, and a trade association in California, New York,
Washington, Rhode Island and (cid:48)(cid:68)(cid:85)(cid:92)(cid:79)(cid:68)(cid:81)(cid:71)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:51)(cid:68)(cid:70)(cid:76)(cid:73)(cid:76)(cid:70)(cid:3)(cid:38)(cid:82)(cid:68)(cid:86)(cid:87)(cid:3)(cid:41)(cid:72)(cid:71)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:86)(cid:75)(cid:72)(cid:85)(cid:80)(cid:72)(cid:81)(cid:182)(cid:86)(cid:3)(cid:36)(cid:86)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)
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.
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.
69
NEW ACCOUNTING STANDARDS
In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, (cid:179)(cid:47)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:180) (ASU No.
2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing
arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, (cid:179)(cid:47)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:180) (FASB
ASC Topic 840), and requires lessees to recognize substantially all lease assets and lease liabilities on the
balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline
requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both
lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018,
and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified
retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No.
2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in
the financial statements.
ASU No. 2016-02 was amended in January 2018 by the provisions of ASU No. 2018-01, (cid:179)(cid:47)(cid:68)(cid:81)(cid:71) Easement
Practical Expedient for Transition to Topic (cid:27)(cid:23)(cid:21)(cid:180) (ASU No. 2018-01), and in July 2018 by the provisions of
ASU No. 2018-10, (cid:179)(cid:38)(cid:82)(cid:71)(cid:76)(cid:73)(cid:76)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81) Improvements to Topic 842, (cid:47)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:180) (ASU No. 2018-10). In addition, ASU
No. 2016-02 was further amended in July 2018 by the provisions of ASU No. 2018-11, (cid:179)(cid:55)(cid:68)(cid:85)(cid:74)(cid:72)(cid:87)(cid:72)(cid:71)
(cid:44)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180) (ASU No. 2018-11), and in December 2018 by the provisions of ASU No. 2018-20, (cid:179)(cid:49)(cid:68)(cid:85)(cid:85)(cid:82)(cid:90)-
Scope Improvements for (cid:47)(cid:72)(cid:86)(cid:86)(cid:82)(cid:85)(cid:86)(cid:180) (ASU No. 2018-20).
ASU No. 2018-11 sets forth certain additional practical expedients for lessors and provides entities with an
option to apply the provisions of ASU No. 2016-02, as amended, to leasing arrangements existing at or entered
into after the (cid:36)(cid:54)(cid:56)(cid:182)(cid:86) effective date of adoption (the (cid:179)(cid:50)(cid:83)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79) Transition (cid:48)(cid:72)(cid:87)(cid:75)(cid:82)(cid:71)(cid:180)(cid:12)(cid:17) Entities that elect to utilize
the Optional Transition Method would not apply the provisions of ASU No. 2016-02, as amended, to
comparative periods presented in the financial statements.
We plan to adopt ASU No. 2016-02, as amended, effective January 1, 2019, utilizing the Optional Transition
Method. Accordingly, the comparative periods presented in the financial statements prior to January 1, 2019,
will be presented pursuant to the existing requirements of FASB ASC Topic 840 and not be adjusted upon the
adoption of the ASU. We also expect to utilize the package of optional transition-related practical expedients
set forth by ASU No. 2016-02, as amended, which permit entities to not reassess upon the adoption of the ASU
certain historical conclusions regarding lease contract identification and classification, as well as the historical
accounting treatment of initial direct costs (the (cid:179)(cid:51)(cid:68)(cid:70)(cid:78)(cid:68)(cid:74)(cid:72) of Optional Practical E(cid:91)(cid:83)(cid:72)(cid:71)(cid:76)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180)(cid:12)(cid:17) For lease
arrangements containing both lease and non-lease components, we will adopt the optional practical expedient
to not separate lease components from non-lease components for all new or modified leases executed on or
after the effective date of the ASU, subject to making any elections for leases after the effective date in new
asset classes. Furthermore, we do not expect to record assets and liabilities on our consolidated balance sheet
for new or existing lease arrangements with terms of 12 months or less.
The expected impact of the adoption of ASU No. 2016-02, as amended, relates primarily to our balance sheet,
resulting from the initial recognition of lease liabilities and corresponding right-of-use assets for our existing
population of operating leases, as well as enhanced disclosure of our leasing arrangements. We expect to
recognize on our consolidated balance sheet approximately $1 billion of operating lease liabilities and
corresponding right-of-use assets upon the adoption of ASU No. 2016-02, as amended. We have implemented
a third-party lease accounting software solution to facilitate the ongoing accounting and financial reporting
requirements of the ASU and also expect the adoption of the ASU to result in certain changes being made to
our existing accounting policies and systems, business processes, and internal controls.
While our evaluation of ASU No. 2016-02, as amended, and related implementation activities approach
completion, we continue to monitor proposals issued by the FASB to clarify the ASU. For additional
information, see Note 26(cid:178)New Accounting Standards, in the Notes to Consolidated Financial Statements.
70
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles 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(cid:178)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 discussions of contingencies and 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 discovered on the prospect.
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 2018, the book value of
the pools of property acquisition costs, that individually are relatively small and thus subject to the above-
described periodic leasehold impairment calculation, was $468 million and the accumulated impairment
reserve was $153 million. The weighted-average judgmental percentage probability of ultimate failure was
approximately 71 percent, and the weighted-average amortization period was approximately two years. If that
judgmental percentage were to be raised by 5 percent across all calculations, before-tax leasehold impairment
expense in 2019 would increase by approximately $7 million. At year-end 2018, the remaining $3.6 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 $2.6 billion is concentrated in 10 major
development areas, the majority of which are not expected to move to proved properties in 2019. Management
periodically assesses individually significant leaseholds for impairment based on the results of exploration and
drilling efforts and the outlook for commercialization.
Exploratory Costs
For exploratory wells, drilling costs are temporarily c(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:15)(cid:3)(cid:82)(cid:85)(cid:3)(cid:179)(cid:86)(cid:88)(cid:86)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:71)(cid:15)(cid:180)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:15)(cid:3)(cid:83)(cid:72)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)
a determination of whether potentially economic oil and gas reserves have been discovered by the drilling
effort to justify development.
71
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 mad(cid:72)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:81)(cid:82)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:179)(cid:86)(cid:88)(cid:73)(cid:73)(cid:76)(cid:70)(cid:76)(cid:72)(cid:81)(cid:87)(cid:3)(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:72)(cid:86)(cid:86)(cid:180)(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:77)(cid:88)(cid:71)(cid:74)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:3)(cid:68)(cid:85)(cid:72)(cid:68)(cid:15)(cid:3)(cid:69)(cid:88)(cid:87)(cid:3)
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 2018, total suspended well costs were $856 million, compared with $853 million at year-end
2017. For additional information on suspended wells, including an aging analysis, see Note 8(cid:178)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
(cid:179)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:180)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:3)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:86)(cid:3)(cid:71)(cid:88)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:76)(cid:80)(cid:83)(cid:82)(cid:85)(cid:87)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:82)(cid:73) these estimates to better understand the perceived value
(cid:68)(cid:81)(cid:71)(cid:3)(cid:73)(cid:88)(cid:87)(cid:88)(cid:85)(cid:72)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:73)(cid:79)(cid:82)(cid:90)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:85)(cid:72)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:86)(cid:72)(cid:89)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3)(cid:68)(cid:88)(cid:87)(cid:75)(cid:82)(cid:85)(cid:76)(cid:87)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:74)(cid:88)(cid:76)(cid:71)(cid:72)(cid:79)(cid:76)(cid:81)(cid:72)(cid:86)(cid:3)(cid:85)(cid:72)(cid:74)(cid:68)(cid:85)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)
(cid:72)(cid:81)(cid:74)(cid:76)(cid:81)(cid:72)(cid:72)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:85)(cid:76)(cid:87)(cid:72)(cid:85)(cid:76)(cid:68)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:80)(cid:88)(cid:86)(cid:87)(cid:3)(cid:69)(cid:72)(cid:3)(cid:80)(cid:72)(cid:87)(cid:3)(cid:69)(cid:72)(cid:73)(cid:82)(cid:85)(cid:72)(cid:3)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:70)(cid:68)(cid:81)(cid:3)(cid:69)(cid:72)(cid:3)(cid:71)(cid:72)(cid:86)(cid:76)(cid:74)(cid:81)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:179)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:17)(cid:180)(cid:3)(cid:3)(cid:50)(cid:88)(cid:85)(cid:3)
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
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.
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Our proved reserves include estimated quantities related to production sharing contracts, reported under the
(cid:179)(cid:72)(cid:70)(cid:82)(cid:81)(cid:82)(cid:80)(cid:76)(cid:70)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:180)(cid:3)(cid:80)(cid:72)(cid:87)(cid:75)(cid:82)(cid:71)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:89)(cid:68)(cid:85)(cid:76)(cid:68)(cid:69)(cid:79)(cid:72)-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 2018, the net book value of productive properties,
plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $37 billion and
the DD&A recorded on these assets in 2018 was approximately $5.5 billion. The estimated proved developed
reserves for our consolidated operations were 3.0 billion BOE at the end of 2017 and 3.3 billion BOE at the
end of 2018. 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 2018 would have increased by an estimated
$611 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(cid:178)generally on a
field-by-field basis for exploration and production 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(cid:178)
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
(cid:87)(cid:75)(cid:72)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:70)(cid:68)(cid:85)(cid:85)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:80)(cid:82)(cid:88)(cid:81)(cid:87)(cid:17)(cid:3)(cid:3)(cid:58)(cid:75)(cid:72)(cid:81)(cid:3)(cid:76)(cid:87)(cid:3)is determined such a loss in value is other than temporary, an
(cid:76)(cid:80)(cid:83)(cid:68)(cid:76)(cid:85)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:70)(cid:75)(cid:68)(cid:85)(cid:74)(cid:72)(cid:3)(cid:76)(cid:86)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:71)(cid:76)(cid:73)(cid:73)(cid:72)(cid:85)(cid:72)(cid:81)(cid:70)(cid:72)(cid:3)(cid:69)(cid:72)(cid:87)(cid:90)(cid:72)(cid:72)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:70)(cid:68)(cid:85)(cid:85)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:89)(cid:68)(cid:79)(cid:88)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:87)(cid:86)(cid:3)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)
fair value. When determining whether a decline in value is other than temporary, management considers
(cid:73)(cid:68)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:86)(cid:88)(cid:70)(cid:75)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:79)(cid:72)(cid:81)(cid:74)(cid:87)(cid:75)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:76)(cid:80)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:72)(cid:91)(cid:87)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:71)(cid:72)(cid:70)(cid:79)(cid:76)(cid:81)(cid:72)(cid:15)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:72)(cid:72)(cid:182)(cid:86)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:81)(cid:72)(cid:68)(cid:85)-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 (cid:179)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:180) section of Note 6(cid:178)Investments,
Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional
information.
73
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 United States 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(cid:178)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
1 percent decrease in the discount rate assumption would increase projected benefit obligations by $1,000
million. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A
1 percent decrease in the discount rate assumption would increase annual benefit expense by $110 million,
while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by
$40 million. In determining the discount rate, we use yields on high-quality fixed income investments
matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum
retirement benefits taken from pension plans during the year could exceed the total of service and interest
components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net
74
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 elimination for a significant number of employees the accrual of defined
benefits for some or all of their future services, we could recognize a curtailment gain or loss. See Note 18(cid:178)
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
(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:72)(cid:86)(cid:17)(cid:3)(cid:3)(cid:41)(cid:82)(cid:85)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:81)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:72)(cid:81)(cid:87)(cid:3)(cid:79)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:15)(cid:3)(cid:86)(cid:72)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:76)(cid:81)(cid:3)(cid:179)(cid:38)(cid:68)(cid:83)(cid:76)(cid:87)(cid:68)(cid:79)(cid:3)
(cid:53)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:47)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:76)(cid:87)(cid:92)(cid:17)(cid:180)
75
(cid:38)(cid:36)(cid:56)(cid:55)(cid:44)(cid:50)(cid:49)(cid:36)(cid:53)(cid:60)(cid:3)(cid:54)(cid:55)(cid:36)(cid:55)(cid:40)(cid:48)(cid:40)(cid:49)(cid:55)(cid:3)(cid:41)(cid:50)(cid:53)(cid:3)(cid:55)(cid:43)(cid:40)(cid:3)(cid:51)(cid:56)(cid:53)(cid:51)(cid:50)(cid:54)(cid:40)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)(cid:55)(cid:43)(cid:40)(cid:3)(cid:179)(cid:54)(cid:36)(cid:41)(cid:40)(cid:3)(cid:43)(cid:36)(cid:53)(cid:37)(cid:50)(cid:53)(cid:180)(cid:3)(cid:51)(cid:53)(cid:50)(cid:57)(cid:44)(cid:54)(cid:44)(cid:50)(cid:49)(cid:54)(cid:3)(cid:50)(cid:41)(cid:3)
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-(cid:79)(cid:82)(cid:82)(cid:78)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:69)(cid:92)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:90)(cid:82)(cid:85)(cid:71)(cid:86)(cid:3)(cid:179)(cid:68)(cid:81)(cid:87)(cid:76)(cid:70)(cid:76)(cid:83)(cid:68)(cid:87)(cid:72)(cid:15)(cid:180)(cid:3)
(cid:179)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:15)(cid:180)(cid:3)(cid:179)(cid:69)(cid:72)(cid:79)(cid:76)(cid:72)(cid:89)(cid:72)(cid:15)(cid:180)(cid:3)(cid:179)(cid:69)(cid:88)(cid:71)(cid:74)(cid:72)(cid:87)(cid:15)(cid:180)(cid:3)(cid:179)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:15)(cid:180)(cid:3)(cid:179)(cid:70)(cid:82)(cid:88)(cid:79)(cid:71)(cid:15)(cid:180)(cid:3)(cid:179)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:71)(cid:15)(cid:180)(cid:3)(cid:179)(cid:80)(cid:68)(cid:92)(cid:15)(cid:180)(cid:3)(cid:179)(cid:83)(cid:79)(cid:68)(cid:81)(cid:15)(cid:180)(cid:3)(cid:179)(cid:83)(cid:82)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:68)(cid:79)(cid:15)(cid:180)(cid:3)(cid:179)(cid:83)(cid:85)(cid:72)(cid:71)(cid:76)(cid:70)(cid:87)(cid:15)(cid:180)(cid:3)(cid:179)(cid:86)(cid:72)(cid:72)(cid:78)(cid:15)(cid:180)(cid:3)
(cid:179)(cid:86)(cid:75)(cid:82)(cid:88)(cid:79)(cid:71)(cid:15)(cid:180)(cid:3)(cid:179)(cid:90)(cid:76)(cid:79)(cid:79)(cid:15)(cid:180)(cid:3)(cid:179)(cid:90)(cid:82)(cid:88)(cid:79)(cid:71)(cid:15)(cid:180)(cid:3)(cid:179)(cid:72)(cid:91)(cid:83)(cid:72)(cid:70)(cid:87)(cid:15)(cid:180)(cid:3)(cid:179)(cid:82)(cid:69)(cid:77)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:15)(cid:180)(cid:3)(cid:179)(cid:83)(cid:85)(cid:82)(cid:77)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:180)(cid:3)(cid:179)(cid:73)(cid:82)(cid:85)(cid:72)(cid:70)(cid:68)(cid:86)(cid:87)(cid:15)(cid:180)(cid:3)(cid:179)(cid:74)(cid:82)(cid:68)(cid:79)(cid:15)(cid:180)(cid:3)(cid:179)(cid:74)(cid:88)(cid:76)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:15)(cid:180)(cid:3)(cid:179)(cid:82)(cid:88)(cid:87)(cid:79)(cid:82)(cid:82)(cid:78)(cid:15)(cid:180)(cid:3)
(cid:179)(cid:72)(cid:73)(cid:73)(cid:82)(cid:85)(cid:87)(cid:15)(cid:180)(cid:3)(cid:179)(cid:87)(cid:68)(cid:85)(cid:74)(cid:72)(cid:87)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:86)(cid:76)(cid:80)(cid:76)(cid:79)(cid:68)(cid:85)(cid:3)(cid:72)(cid:91)(cid:83)(cid:85)(cid:72)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:3)
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:
(cid:120) Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, including a
prolonged decline in these prices relative to historical or future expected levels.
(cid:120) The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and natural gas
liquids, which may result in recognition of impairment costs on our long-lived assets, leaseholds and
nonconsolidated equity investments.
(cid:120) 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.
(cid:120) Reductions in reserves replacement rates, whether as a result of the significant declines in commodity
prices or otherwise.
(cid:120) Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
(cid:120) Unexpected changes in costs or technical requirements for constructing, modifying or operating
exploration and production facilities.
(cid:120) 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.
(cid:120) Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas,
(cid:120)
LNG and natural gas liquids.
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.
(cid:120) 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.
(cid:120) Potential disruption or interruption of our operations due to accidents, extraordinary weather events,
civil unrest, political events, war, terrorism, cyber attacks, and information technology failures,
constraints or disruptions.
(cid:120) Changes in international monetary conditions and foreign currency exchange rate fluctuations.
76
(cid:120) Changes in international trade relationships, including the imposition of trade restrictions or tariffs
relating to crude oil, bitumen, natural gas, LNG, natural gas liquids and any materials or products
(such as aluminum and steel) used in the operation of our business.
(cid:120) Reduced demand for our products or the use of competing energy products, including alternative
energy sources.
(cid:120) Substantial investment in and development of alternative energy sources, including as a result of
existing or future environmental rules and regulations.
(cid:120) Liability for remedial actions, including removal and reclamation obligations, under environmental
regulations.
(cid:120) Liability resulting from litigation or our failure to comply with applicable laws and regulations.
(cid:120) 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 natural gas liquids pricing, regulation or taxation; the impact of and uncertainty surrounding
(cid:87)(cid:75)(cid:72)(cid:3)(cid:56)(cid:81)(cid:76)(cid:87)(cid:72)(cid:71)(cid:3)(cid:46)(cid:76)(cid:81)(cid:74)(cid:71)(cid:82)(cid:80)(cid:182)(cid:86)(cid:3)(cid:71)(cid:72)(cid:70)(cid:76)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:87)(cid:82)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:71)(cid:85)(cid:68)(cid:90)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:40)(cid:88)(cid:85)(cid:82)(cid:83)(cid:72)(cid:68)(cid:81)(cid:3)(cid:56)(cid:81)(cid:76)(cid:82)(cid:81)(cid:30)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:83)(cid:82)(cid:79)(cid:76)(cid:87)(cid:76)(cid:70)(cid:68)(cid:79)(cid:15)(cid:3)(cid:72)(cid:70)(cid:82)(cid:81)(cid:82)(cid:80)(cid:76)(cid:70)(cid:3)
or diplomatic developments.
(cid:120) Volatility in the commodity futures markets.
(cid:120) 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.
(cid:120) Competition in the oil and gas exploration and production industry.
(cid:120) 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.
(cid:120) Our inability to execute, or delays in the completion, of any asset dispositions or acquisitions we elect
to pursue.
(cid:120) 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.
(cid:120) Potential disruption of our operations as a result of asset dispositions or acquisitions, including the
diversion of management time and attention.
(cid:120) Our inability to deploy the net proceeds from any asset dispositions we undertake in the manner and
timeframe we currently anticipate, if at all.
(cid:120) 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.
(cid:120) The operation and financing of our joint ventures.
(cid:120) The ability of our customers and other contractual counterparties to satisfy their obligations to us,
including our inability to collect payments when due under our ICC settlement agreement with
PDVSA.
(cid:120) Our inability to realize anticipated cost savings and expenditure reductions.
(cid:120) The factors generally described in Item 1A(cid:178)Risk Factors in this 2018 Annual Report on Form 10-K
and any additional risks described in our other filings with the SEC.
77
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.
(cid:50)(cid:88)(cid:85)(cid:3)(cid:88)(cid:86)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:71)(cid:72)(cid:85)(cid:76)(cid:89)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:76)(cid:81)(cid:86)(cid:87)(cid:85)(cid:88)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)(cid:74)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:68)(cid:81)(cid:3)(cid:179)(cid:36)(cid:88)(cid:87)(cid:75)(cid:82)(cid:85)(cid:76)(cid:87)(cid:92)(cid:3)(cid:47)(cid:76)(cid:80)(cid:76)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:71)(cid:82)(cid:70)(cid:88)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:83)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:37)(cid:82)(cid:68)(cid:85)(cid:71)(cid:3)
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:
(cid:120) 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.
(cid:120) 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, 2018, 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, 2018 and 2017, was immaterial to our
consolidated cash flows and net income attributable to ConocoPhillips.
Interest Rate Risk
The following table provides information about our financial instruments that are sensitive to changes in U.S.
interest rates. The debt portion of 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
financial instruments is estimated based on quoted market prices.
78
Expected Maturity Date
Year-End 2018
2019
2020
2021
2022
2023
Remaining years
Total
Fair value
Year-End 2017
2018
2019
2020
2021
2022
Remaining years
Total
Fair value
Millions of Dollars Except as Indicated
Debt
Fixed
Rate
Maturity
Average
Interest
Rate
Floating
Rate
Maturity
Average
Interest
Rate
$
$
$
$
$
$
17
-
123
343
106
12,599
13,188
15,364
2,250
23
-
150
1,014
14,207
17,644
21,402
- % $
-
9.13
2.54
7.20
6.16
$
$
3.31 % $
-
-
9.13
2.45
6.00
$
$
-
-
-
500
-
283
783
783
250
-
-
-
500
283
1,033
1,033
- %
-
-
3.52
-
1.78
1.75 %
-
-
-
2.32
1.70
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, 2018 and 2017, 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, 2018 and 2017, we had outstanding foreign currency zero-cost collars buying the right to sell
$1.25 billion Canadian dollars (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, 2018 and December 31, 2017, was a before-tax gain
of $6 million and a before-tax loss of $9 million, respectively. Based on an adverse hypothetical 10 percent
change in the December 2018 and December 2017 exchange rate, this would result in an additional before-tax
loss of $17 million and $74 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.
79
The gross notional and fair market values of these positions at December 31, 2018 and 2017, were as follows:
Foreign Currency Exchange Derivatives
In Millions
Notional*
2018
Fair Market Value**
2017
2018
2017
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
*Denominated in U.S. dollars (USD), Canadian dollars (CAD) and British pound (GBP).
**Denominated in U.S. dollars.
805
1,250
8
9
12
USD
CAD
CAD
GBP
GBP
-
1,250
25
-
1
(5)
6
-
-
-
-
(9)
1
-
-
For additional information about our use of derivative instruments, see Note 14(cid:178)Derivative and Financial
Instruments, in the Notes to Consolidated Financial Statements.
80
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
Report of Management ...........................................................................................................................
Page
82
INDEX TO FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm .................................................................
83
Consolidated Income Statement for the years ended December 31, 2018, 2017 and 2016 ....................
85
Consolidated Statement of Comprehensive Income for the years ended
December 31, 2018, 2017 and 2016 ..................................................................................................
86
Consolidated Balance Sheet at December 31, 2018 and 2017 ................................................................
87
Consolidated Statement of Cash Flows for the years ended December 31, 2018, 2017 and 2016 .........
88
Consolidated Statement of Changes in Equity for the years ended
December 31, 2018, 2017 and 2016 ..................................................................................................
89
Notes to Consolidated Financial Statements ...........................................................................................
90
Supplementary Information
Oil and Gas Operations .............................................................................................................
153
Selected Quarterly Financial Data .............................................................................................
180
Condensed Consolidating Financial Information ......................................................................
181
81
Report of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information
(cid:68)(cid:83)(cid:83)(cid:72)(cid:68)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:68)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:3)(cid:73)(cid:68)(cid:76)(cid:85)(cid:79)(cid:92)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)
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
(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:69)(cid:72)(cid:72)(cid:81)(cid:3)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:40)(cid:85)(cid:81)(cid:86)(cid:87)(cid:3)(cid:9)(cid:3)(cid:60)(cid:82)(cid:88)(cid:81)(cid:74)(cid:3)(cid:47)(cid:47)(cid:51)(cid:15)(cid:3)(cid:68)(cid:81)(cid:3)(cid:76)(cid:81)(cid:71)(cid:72)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:85)(cid:72)(cid:74)(cid:76)(cid:86)(cid:87)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:83)(cid:88)(cid:69)(cid:79)(cid:76)(cid:70)(cid:3)
accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by
stockholders. Manageme(cid:81)(cid:87)(cid:3)(cid:75)(cid:68)(cid:86)(cid:3)(cid:80)(cid:68)(cid:71)(cid:72)(cid:3)(cid:68)(cid:89)(cid:68)(cid:76)(cid:79)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:40)(cid:85)(cid:81)(cid:86)(cid:87)(cid:3)(cid:9)(cid:3)(cid:60)(cid:82)(cid:88)(cid:81)(cid:74)(cid:3)(cid:47)(cid:47)(cid:51)(cid:3)(cid:68)(cid:79)(cid:79)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:85)(cid:71)(cid:86)(cid:3)
(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:71)(cid:68)(cid:87)(cid:68)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:80)(cid:76)(cid:81)(cid:88)(cid:87)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:71)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:182)(cid:3)(cid:80)(cid:72)(cid:72)(cid:87)(cid:76)(cid:81)(cid:74)(cid:86)(cid:17)
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial
(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:17)(cid:3)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:86)(cid:92)(cid:86)(cid:87)(cid:72)(cid:80)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:71)(cid:72)(cid:86)(cid:76)(cid:74)(cid:81)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:3)(cid:85)(cid:72)(cid:68)(cid:86)(cid:82)(cid:81)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:68)(cid:86)(cid:86)(cid:88)(cid:85)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)
(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:71)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:85)(cid:72)(cid:74)(cid:68)(cid:85)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:83)(cid:85)(cid:72)(cid:83)(cid:68)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:73)air 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.
(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:86)(cid:86)(cid:72)(cid:86)(cid:86)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:72)(cid:73)(cid:73)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)
December 31, 2018. 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
(cid:68)(cid:86)(cid:86)(cid:72)(cid:86)(cid:86)(cid:80)(cid:72)(cid:81)(cid:87)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:69)(cid:72)(cid:79)(cid:76)(cid:72)(cid:89)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:72)(cid:73)(cid:73)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:68)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)
December 31, 2018.
Ernst & Young LLP has issued (cid:68)(cid:81)(cid:3)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)
December 31, 2018, and their report is included herein.
/s/ Ryan M. Lance
Ryan M. Lance
Chairman and
Chief Executive Officer
February 19, 2019
/s/ Don E. Wallette, Jr.
Don E. Wallette, Jr.
Executive Vice President and
Chief Financial Officer
82
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 as of December 31, 2018
and 2017, and 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, 2018, 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 t(cid:82)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180)(cid:12)(cid:17)(cid:3)(cid:44)(cid:81)(cid:3)
our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of ConocoPhillips at December 31, 2018 and 2017, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 2018, 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
(cid:11)(cid:56)(cid:81)(cid:76)(cid:87)(cid:72)(cid:71)(cid:3)(cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:86)(cid:12)(cid:3)(cid:11)(cid:51)(cid:38)(cid:36)(cid:50)(cid:37)(cid:12)(cid:15)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)2018,
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 19,
2019, expressed an unqualified opinion thereon.
Basis for Opinion
(cid:55)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:76)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)(cid:3)(cid:50)(cid:88)(cid:85)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:76)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)
express an opinion (cid:82)(cid:81)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:86)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:68)(cid:3)(cid:83)(cid:88)(cid:69)(cid:79)(cid:76)(cid:70)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)
firm registered with the PCAOB and are required to be independent with respect to ConocoPhillips 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.
/s/ Ernst & Young LLP
(cid:58)(cid:72)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:82)(cid:85)(cid:3)(cid:86)(cid:76)(cid:81)(cid:70)(cid:72)(cid:3)(cid:20)(cid:28)(cid:23)(cid:28)(cid:17)
Houston, Texas
February 19, 2019
83
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of ConocoPhillips
Opinion on Internal Control over Financial Reporting
(cid:58)(cid:72)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:72)(cid:71)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)ntrol over financial reporting as of December 31, 2018, 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
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018,
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 as of December 31, 2018 and 2017, and 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, 2018, and the related notes, condensed consolidating financial
information listed in the Index at Item 8, and financial statement schedule listed in Item 15(a) of ConocoPhillips and
our report dated February 19, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:76)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:76)(cid:69)(cid:79)(cid:72)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:80)(cid:68)(cid:76)(cid:81)(cid:87)(cid:68)(cid:76)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:72)(cid:73)(cid:73)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
for its assessment of the effectiveness of internal control over financial reporting included under the heading
(cid:179)(cid:36)(cid:86)(cid:86)(cid:72)(cid:86)(cid:86)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:44)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:50)(cid:89)(cid:72)(cid:85)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:180)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:179)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)(cid:180)(cid:3)(cid:50)(cid:88)(cid:85)(cid:3)
(cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:86)(cid:76)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:72)(cid:91)(cid:83)(cid:85)(cid:72)(cid:86)(cid:86)(cid:3)(cid:68)(cid:81)(cid:3)(cid:82)(cid:83)(cid:76)(cid:81)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:81)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)
audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect
to ConocoPhillips 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
(cid:36)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:3)(cid:71)(cid:72)(cid:86)(cid:76)(cid:74)(cid:81)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:3)(cid:85)(cid:72)(cid:68)(cid:86)(cid:82)(cid:81)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:68)(cid:86)(cid:86)(cid:88)(cid:85)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally acce(cid:83)(cid:87)(cid:72)(cid:71)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:83)(cid:85)(cid:76)(cid:81)(cid:70)(cid:76)(cid:83)(cid:79)(cid:72)(cid:86)(cid:17)(cid:3)(cid:36)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)
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
(cid:68)(cid:86)(cid:86)(cid:88)(cid:85)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:85)(cid:72)(cid:74)(cid:68)(cid:85)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:83)(cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:85)(cid:3)(cid:87)(cid:76)(cid:80)(cid:72)(cid:79)(cid:92)(cid:3)(cid:71)(cid:72)(cid:87)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:88)(cid:81)(cid:68)(cid:88)(cid:87)(cid:75)(cid:82)(cid:85)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:68)(cid:70)(cid:84)(cid:88)(cid:76)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:88)(cid:86)(cid:72)(cid:15)(cid:3)(cid:82)(cid:85)(cid:3)(cid:71)(cid:76)(cid:86)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)
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 19, 2019
84
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
Millions of Dollars
2017*
2018
2016*
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)
23,693
52
360
255
24,360
9,994
5,643
473
1,912
9,062
139
739
425
1,245
(19)
277
29,890
(5,530)
(1,971)
(3,559)
(56)
(3,615)
5.36
5.32
(0.70)
(0.70)
(2.91)
(2.91)
$
$
$
Average Common Shares Outstanding (in thousands)
Basic
Diluted
*Certain amounts have been reclassified to conform to the current-period presentation resulting from the adoption of ASU No. 2017-07. See
Note 2(cid:886)Changes in Accounting Principles, for additional information.
See Notes to Consolidated Financial Statements.
1,221,038
1,221,038
1,166,499
1,175,538
1,245,440
1,245,440
85
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years Ended December 31
Millions of Dollars
2018
2017
2016
$
2
(7)
23
(793)
6,305
(3,559)
(38)
(36)
19
(35)
(12)
(481)
(40)
(47)
(150)
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 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
Reclassification adjustment for gain included in net loss
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 Note 2(cid:886)Changes in Accounting Principles and Note 20(cid:886)Accumulated Other Comprehensive Loss, for additional information relating to
the adoption of ASU No. 2016-01.
See Notes to Consolidated Financial Statements.
279
129
(1)
(42)
39
-
-
(645)
-
3
(642)
(603)
5,702
(48)
5,654
247
266
(2)
(81)
147
(58)
(58)
586
-
-
586
675
(118)
(62)
(180)
309
(172)
2
78
(104)
-
-
153
5
-
158
54
(3,505)
(56)
(3,561)
$
86
Consolidated Balance Sheet
At December 31
Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable (net of allowance of $25 million in 2018
and $4 million in 2017)
Accounts and notes receivable(cid:178)related parties
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Loans and advances(cid:178)related parties
Net properties, plants and equipment (net of accumulated depreciation, depletion
and amortization of $64,899 million in 2018 and $64,748 million in 2017)
Other assets
Total Assets
Liabilities
Accounts payable
Accounts payable(cid:178)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 $.01 par value)
Issued (2018(cid:178)1,791,637,434 shares; 2017(cid:178)1,785,419,175 shares)
Par value
Capital in excess of par
Treasury stock (at cost: 2018(cid:178)653,288,213 shares; 2017(cid:178)608,312,034 shares)
Accumulated other comprehensive loss
Retained earnings
(cid:55)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)
Noncontrolling interests
Total Equity
Total Liabilities and Equity
See Notes to Consolidated Financial Statements.
ConocoPhillips
Millions of Dollars
2018
2017
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
6,325
1,873
4,179
141
1,899
1,060
1,035
16,512
9,599
461
45,683
1,107
73,362
4,009
21
2,575
1,038
725
1,029
9,397
17,128
7,631
5,282
1,854
1,269
42,561
18
46,879
(42,905)
(6,063)
34,010
31,939
125
32,064
69,980
18
46,622
(39,906)
(5,518)
29,391
30,607
194
30,801
73,362
$
$
$
$
87
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 short-term investments
Collection of advances/loans(cid:178)related parties
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 Provided by (Used in) Financing Activities
Millions of Dollars
2018
2017
2016
$
6,305
(793)
(3,559)
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)
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)
9,062
139
1,184
425
(2,221)
299
(360)
(85)
820
44
105
(524)
(926)
4,403
(4,869)
(331)
1,286
(51)
108
(2)
(3,859)
4,594
(2,251)
(63)
(126)
(1,253)
(137)
764
Effect of Exchange Rate Changes on Cash, Cash Equivalents
and Restricted Cash
(117)
232
(66)
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
*Restated to include $211 million of restricted cash at January 1, 2018. See Note 2(cid:886)Changes in Accounting Principles for additional
information relating to the adoption of ASU No. 2016-18.
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
2,715
3,610
6,325
$
1,242
2,368
3,610
88
Consolidated Statement of Changes in Equity
ConocoPhillips
Retained
Earnings
36,414
(3,615)
(1,253)
2
31,548
(855)
(1,305)
3
29,391
6,257
(1,363)
(278)
3
34,010
Non-
Controlling
Interests
320
56
(124)
252
62
(120)
194
48
(121)
4
125
Total
40,082
(3,559)
54
(1,253)
(126)
(124)
150
2
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
Attributable to ConocoPhillips
Millions of Dollars
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
18
$
$
December 31, 2015
Net income (loss)
Other comprehensive income
Dividends paid ($1.00/share of common stock)
Repurchase of company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Other
December 31, 2016
Net income (loss)
Other comprehensive income
Dividends paid ($1.06/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/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
*See Note 2(cid:886)Changes in Accounting Principles for additional information.
See Notes to Consolidated Financial Statements.
$
$
18
18
18
46,357
(36,780)
(6,247)
54
(126)
150
46,507
(36,906)
(6,193)
675
(3,000)
115
46,622
(39,906)
(5,518)
(2,999)
257
(603)
58
46,879
(42,905)
(6,063)
89
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1(cid:178)Accounting Policies
(cid:132) Consolidation Principles and Investments(cid:178)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
(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:72)(cid:91)(cid:72)(cid:85)(cid:87)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:73)(cid:76)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:73)(cid:79)(cid:88)(cid:72)(cid:81)(cid:70)(cid:72)(cid:3)(cid:82)(cid:89)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:73)(cid:73)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:72)(cid:86)(cid:182)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:83)(cid:82)(cid:79)(cid:76)(cid:70)(cid:76)(cid:72)(cid:86)(cid:17)(cid:3)(cid:3)(cid:58)(cid:75)(cid:72)(cid:81)(cid:3)(cid:90)(cid:72)(cid:3)(cid:71)(cid:82)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)
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(cid:178)Segment Disclosures and Related Information.
(cid:132) Foreign Currency Translation(cid:178)Adjustments resulting from the process of translating foreign
functional currency financial statements into U.S. dollars are included in accumulated other
(cid:70)(cid:82)(cid:80)(cid:83)(cid:85)(cid:72)(cid:75)(cid:72)(cid:81)(cid:86)(cid:76)(cid:89)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)(cid:17)(cid:3)(cid:3)(cid:41)(cid:82)(cid:85)(cid:72)(cid:76)(cid:74)(cid:81)(cid:3)(cid:70)(cid:88)(cid:85)(cid:85)(cid:72)(cid:81)(cid:70)(cid:92)(cid:3)(cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:68)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:74)(cid:68)(cid:76)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:79)(cid:82)(cid:86)(cid:86)(cid:72)(cid:86)(cid:3)
are included in current earnings. Some of our foreign operations use their local currency as the functional
currency.
(cid:132) Use of Estimates(cid:178)The preparation of financial statements in conformity with accounting principles
generally accepted in the United States 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.
(cid:132) Revenue Recognition(cid:178)Revenues associated with the sales of crude oil, bitumen, natural gas, liquified
natural gas (LNG), natural gas liquids 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
(cid:82)(cid:73)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:81)(cid:87)(cid:82)(cid:85)(cid:92)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:68)(cid:80)(cid:72)(cid:3)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:72)(cid:85)(cid:83)(cid:68)(cid:85)(cid:87)(cid:92)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:72)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:87)(cid:82)(cid:3)(cid:179)(cid:76)(cid:81)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:72)(cid:80)(cid:83)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:180)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:81)(cid:72)(cid:3)(cid:68)(cid:81)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:15)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:69)(cid:76)(cid:81)(cid:72)(cid:71)(cid:3)
and reported net (i.e., on the same income statement line).
(cid:132) Shipping and Handling Costs(cid:178)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.
(cid:132) Cash Equivalents(cid:178)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.
90
(cid:132) Short-Term Investments(cid:178)Investments in bank time deposits and marketable securities (commercial
paper and government obligations) with original maturities of greater than 90 days but less than one year
are classified as short-term investments.
(cid:132)
Inventories(cid:178)We have several valuation methods for our various types of inventories and consistently
use the following methods for each type of inventory. Our commodity-related inventories are recorded at
cost primarily using the last-in, first-out (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
first-in, first-out (FIFO) method, consistent with industry practice.
(cid:132) Fair Value Measurements(cid:178)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.
(cid:132) Derivative Instruments(cid:178)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.
(cid:132) Oil and Gas Exploration and Development(cid:178)Oil and gas exploration and development costs are
accounted for using the successful efforts method of accounting.
Property Acquisition Costs(cid:178)Oil and gas leasehold acquisition costs are capitalized and included in
the balance sheet caption properties, plants and equipment (PP&E). Leasehold impairment is
(cid:85)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:72)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:82)(cid:85)(cid:92)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:85)(cid:76)(cid:72)(cid:81)(cid:70)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:77)(cid:88)(cid:71)(cid:74)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)(cid:3)(cid:3)(cid:56)pon achievement of all
conditions necessary for reserves to be classified as proved, the associated leasehold costs are
reclassified to proved properties.
Exploratory Costs(cid:178)Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or
(cid:179)(cid:86)(cid:88)(cid:86)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:71)(cid:15)(cid:180)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:3)(cid:83)(cid:72)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:73)(cid:88)(cid:85)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:72)(cid:89)(cid:68)(cid:79)(cid:88)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:90)(cid:75)(cid:72)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:72)(cid:70)(cid:82)(cid:81)(cid:82)(cid:80)(cid:76)(cid:70)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:89)(cid:72)(cid:85)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)
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
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.
91
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(cid:178)
Suspended Wells and Other Exploration Expenses, for additional information on suspended wells.
Development Costs(cid:178)Costs incurred to drill and equip development wells, including unsuccessful
development wells, are capitalized.
Depletion and Amortization(cid:178)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.
(cid:132) Capitalized Interest(cid:178)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.
(cid:132) Depreciation and Amortization(cid:178)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).
(cid:132)
Impairment of Properties, Plants and Equipment(cid:178)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(cid:178)
generally on a field-by-field basis for exploration and production 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.
92
(cid:132)
Impairment of Investments in Nonconsolidated Entities(cid:178)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.
(cid:132) Maintenance and Repairs(cid:178)Costs of maintenance and repairs, which are not significant improvements,
are expensed when incurred.
(cid:132) Property Dispositions(cid:178)When complete units of depreciable property are sold, the asset cost and related
(cid:68)(cid:70)(cid:70)(cid:88)(cid:80)(cid:88)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:71)(cid:72)(cid:83)(cid:85)(cid:72)(cid:70)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:72)(cid:79)(cid:76)(cid:80)(cid:76)(cid:81)(cid:68)(cid:87)(cid:72)(cid:71)(cid:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:81)(cid:92)(cid:3)(cid:74)(cid:68)(cid:76)(cid:81)(cid:3)(cid:82)(cid:85)(cid:3)(cid:79)(cid:82)(cid:86)(cid:86)(cid:3)(cid:85)(cid:72)(cid:73)(cid:79)(cid:72)(cid:70)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:42)(cid:68)(cid:76)(cid:81)(cid:3)(cid:82)(cid:81)(cid:3)(cid:71)(cid:76)(cid:86)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)
of our consolidated income statement. When less than complete units of depreciable property are
disposed of or retired which do not significantly alter the depreciation, depletion and amortization
(DD&A) rate, the difference between asset cost and salvage value is charged or credited to accumulated
depreciation.
(cid:132) Asset Retirement Obligations and Environmental Costs(cid:178)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(cid:178)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.
(cid:132) Guarantees(cid:178)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.
(cid:132) Share-Based Compensation(cid:178)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.
93
(cid:132)
Income Taxes(cid:178)Deferred income taxes are computed using the liability method and are provided on all
temporary differences between the financial reporting basis and the tax basis of our assets and liabilities,
except for deferred taxes on income and temporary differences related to the cumulative translation
adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate
joint ventures. Allowable tax credits are applied currently as reductions of the provision for income
taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties
related to unrecognized tax benefits are reflected in production and operating expenses.
(cid:132) Taxes Collected from Customers and Remitted to Governmental Authorities(cid:178)Sales and value-
added taxes are recorded net.
(cid:132) Net Income (Loss) Per Share of Common Stock(cid:178)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(cid:178)Changes in Accounting Principles
We adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update
(ASU) No. 2014-(cid:19)(cid:28)(cid:15)(cid:3)(cid:179)(cid:53)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:38)(cid:82)(cid:81)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:38)(cid:88)(cid:86)(cid:87)(cid:82)(cid:80)(cid:72)(cid:85)(cid:86)(cid:15)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:87)(cid:86)(cid:3)(cid:68)(cid:80)(cid:72)(cid:81)(cid:71)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:76)(cid:86)(cid:86)(cid:88)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:86)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)
of ASU No. 2016-(cid:19)(cid:27)(cid:15)(cid:3)(cid:179)(cid:51)(cid:85)(cid:76)(cid:81)(cid:70)(cid:76)(cid:83)(cid:68)(cid:79)(cid:3)(cid:89)(cid:72)(cid:85)(cid:86)(cid:88)(cid:86)(cid:3)(cid:36)(cid:74)(cid:72)(cid:81)(cid:87)(cid:3)(cid:38)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:11)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:53)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:3)(cid:42)(cid:85)(cid:82)(cid:86)(cid:86)(cid:3)(cid:89)(cid:72)(cid:85)(cid:86)(cid:88)(cid:86)(cid:3)(cid:49)(cid:72)(cid:87)(cid:12)(cid:15)(cid:180)(cid:3)(cid:36)(cid:54)(cid:56)(cid:3)
No. 2016-(cid:20)(cid:19)(cid:15)(cid:3)(cid:179)(cid:44)(cid:71)(cid:72)(cid:81)(cid:87)(cid:76)(cid:73)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:51)(cid:72)(cid:85)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:50)(cid:69)(cid:79)(cid:76)(cid:74)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:47)(cid:76)(cid:70)(cid:72)(cid:81)(cid:86)(cid:76)(cid:81)(cid:74)(cid:15)(cid:180)(cid:3)(cid:36)(cid:54)(cid:56)(cid:3)(cid:49)(cid:82)(cid:17)(cid:3)(cid:21)(cid:19)(cid:20)(cid:25)-(cid:20)(cid:21)(cid:15)(cid:3)(cid:179)(cid:49)(cid:68)(cid:85)(cid:85)(cid:82)(cid:90)-Scope
(cid:44)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:51)(cid:85)(cid:68)(cid:70)(cid:87)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:40)(cid:91)(cid:83)(cid:72)(cid:71)(cid:76)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:54)(cid:56)(cid:3)(cid:49)(cid:82)(cid:17)(cid:3)(cid:21)(cid:19)(cid:20)(cid:25)-(cid:21)(cid:19)(cid:15)(cid:3)(cid:179)(cid:55)(cid:72)(cid:70)(cid:75)(cid:81)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:85)(cid:85)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:44)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)
Topic 606, Revenu(cid:72)(cid:3)(cid:41)(cid:85)(cid:82)(cid:80)(cid:3)(cid:38)(cid:82)(cid:81)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:38)(cid:88)(cid:86)(cid:87)(cid:82)(cid:80)(cid:72)(cid:85)(cid:86)(cid:15)(cid:180)(cid:3)(cid:70)(cid:82)(cid:79)(cid:79)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:79)(cid:92)(cid:3)(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:54)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:86)(cid:3)(cid:38)(cid:82)(cid:71)(cid:76)(cid:73)(cid:76)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:11)(cid:36)(cid:54)(cid:38)(cid:12)(cid:3)
(cid:55)(cid:82)(cid:83)(cid:76)(cid:70)(cid:3)(cid:25)(cid:19)(cid:25)(cid:15)(cid:3)(cid:179)(cid:53)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:38)(cid:82)(cid:81)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:38)(cid:88)(cid:86)(cid:87)(cid:82)(cid:80)(cid:72)(cid:85)(cid:86)(cid:15)(cid:180)(cid:3)(cid:11)(cid:36)(cid:54)(cid:38)(cid:3)(cid:55)(cid:82)(cid:83)(cid:76)(cid:70)(cid:3)(cid:25)(cid:19)(cid:25)(cid:12)(cid:3)(cid:69)(cid:72)(cid:74)(cid:76)(cid:81)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:17)(cid:3)(cid:3)(cid:36)(cid:54)(cid:38)(cid:3)
Topic 606 outlines a single comprehensive model for an entity to use in accounting for revenue arising from all
contracts with customers except where revenues are in scope of another accounting standard. The ASU
(cid:86)(cid:88)(cid:83)(cid:72)(cid:85)(cid:86)(cid:72)(cid:71)(cid:72)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:85)(cid:72)(cid:84)(cid:88)(cid:76)(cid:85)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:36)(cid:54)(cid:38)(cid:3)(cid:55)(cid:82)(cid:83)(cid:76)(cid:70)(cid:3)(cid:25)(cid:19)(cid:24)(cid:15)(cid:3)(cid:179)(cid:53)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:3)(cid:53)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:80)(cid:82)(cid:86)(cid:87)(cid:3)
industry-specific guidance. ASC Topic 606 sets forth a five-step model for determining when and how
revenue is recognized. Under the model, an entity is required to recognize revenue to depict the transfer of
goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for
those goods and services. ASC Topic 606 also requires certain additional revenue-related disclosures. The
adoption of ASC Topic 606 did not have a material impact on our consolidated financial statements. See
Note 24(cid:178)Sales and Other Operating Revenues for additional information related to this ASC.
We adopted the provisions of FASB ASU No. 2016-(cid:19)(cid:20)(cid:15)(cid:3)(cid:179)(cid:53)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:48)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:36)(cid:86)(cid:86)(cid:72)(cid:87)(cid:86)(cid:3)
(cid:68)(cid:81)(cid:71)(cid:3)(cid:47)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:15)(cid:180)(cid:3)(cid:11)(cid:36)(cid:54)(cid:56)(cid:3)(cid:49)(cid:82)(cid:17)(cid:3)(cid:21)(cid:19)(cid:20)(cid:25)-01) beginning January 1, 2018. The ASU, among other things, requires an
entity to record the changes in fair value of equity investments, other than investments accounted for using the
equity method, within net income. Under this ASU, an entity is no longer able to recognize unrealized holding
gains and losses on equity securities in other comprehensive income and instead must recognize them in the
income statement. See Note 7(cid:178)Investment in Cenovus Energy and Note 20(cid:178)Accumulated Other
Comprehensive Loss for additional information relating to this ASU.
94
The cumulative effect of the changes made to our consolidated balance sheet at January 1, 2018, for the
adoption of ASC Topic 606 and ASU No. 2016-01 were as follows:
Millions of Dollars
December 31 ASC Topic 606 ASU No. 2016-01 January 1
2018
2017 Adjustments
Adjustments
Liabilities
Other accruals
Total current liabilities
Deferred income taxes
Other liabilities and deferred credits
Total liabilities
$
1,029
9,397
5,282
1,269
42,561
104
104
(31)
147
220
-
-
-
-
-
1,133
9,501
5,251
1,416
42,781
Equity
Accumulated other comprehensive loss
Retained earnings
Total common stockholders' equity
Total equity
For discussion of adjustments for ASU No. 2016-01 and ASC Topic 606, see Note 7—Investment in Cenovus Energy and Note 24—Sales and
Other Operating Revenues, respectively.
(5,518)
29,391
30,607
30,801
-
(220)
(220)
(220)
58
(58)
-
-
(5,460)
29,113
30,387
30,581
$
We adopted the provisions of FASB ASU No. 2017-(cid:19)(cid:26)(cid:15)(cid:3)(cid:179)(cid:44)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:51)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:49)(cid:72)(cid:87)(cid:3)(cid:51)(cid:72)(cid:85)(cid:76)(cid:82)(cid:71)(cid:76)(cid:70)(cid:3)(cid:51)(cid:72)(cid:81)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)
(cid:38)(cid:82)(cid:86)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:49)(cid:72)(cid:87)(cid:3)(cid:51)(cid:72)(cid:85)(cid:76)(cid:82)(cid:71)(cid:76)(cid:70)(cid:3)(cid:51)(cid:82)(cid:86)(cid:87)(cid:85)(cid:72)(cid:87)(cid:76)(cid:85)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:37)(cid:72)(cid:81)(cid:72)(cid:73)(cid:76)(cid:87)(cid:3)(cid:38)(cid:82)(cid:86)(cid:87)(cid:15)(cid:180)(cid:3)(cid:69)(cid:72)(cid:74)(cid:76)(cid:81)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:17)(cid:3)(cid:3)(cid:58)(cid:72)(cid:3)(cid:85)(cid:72)(cid:87)(cid:85)(cid:82)(cid:86)(cid:83)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:79)(cid:92)(cid:3)(cid:68)(cid:83)(cid:83)(cid:79)(cid:76)(cid:72)(cid:71)(cid:3)
the presentation of service cost separate from the other components of net periodic costs. The interest cost,
expected return on plan assets, amortization of prior service cost/credit, recognized net actuarial loss/gain,
settlement expense, curtailment loss/gain, and special termination benefits have been reclassified from the
(cid:179)(cid:51)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:15)(cid:180)(cid:3)(cid:179)(cid:54)(cid:72)(cid:79)(cid:79)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)(cid:74)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:71)(cid:80)(cid:76)(cid:81)(cid:76)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:15)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:179)(cid:40)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:86) (cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)(cid:3)(cid:3)We elected to apply the
practical expedient which allows us to reclassify amounts disclosed previously in the employee benefit plans
footnote as the basis for applying retrospective presentation for prior comparative periods as it is impracticable
to determine the disaggregation of the cost components for amounts capitalized and amortized in those periods.
On a prospective basis, the other components of net periodic benefit costs will not be included in amounts
capitalized in inventory or PP&E.
The effect of the retrospective presentation change related to the net periodic benefit cost of our defined benefit
pension and other postretirement employee benefits plans on our consolidated income statement was as
follows:
Year Ended December 31, 2017
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Other expenses
Year Ended December 31, 2016
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Other expenses
95
Millions of Dollars
Previously Effect of Change
As
Reported Higher/(Lower) Revised
$
(cid:3)
$
5,173
561
938
302
(cid:3) (cid:3)
5,667
723
1,915
-
(11)
(134)
(4)
149
(cid:3) (cid:3)
(24)
(250)
(3)
277
5,162
427
934
451
5,643
473
1,912
277
We adopted the provisions of FASB ASU No. 2016-(cid:20)(cid:24)(cid:15)(cid:3)(cid:179)(cid:38)(cid:79)(cid:68)(cid:86)(cid:86)(cid:76)(cid:73)(cid:76)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:38)(cid:72)(cid:85)(cid:87)(cid:68)(cid:76)(cid:81)(cid:3)(cid:38)(cid:68)(cid:86)(cid:75)(cid:3)(cid:53)(cid:72)(cid:70)(cid:72)(cid:76)(cid:83)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:38)(cid:68)(cid:86)(cid:75)(cid:3)
(cid:51)(cid:68)(cid:92)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:180)(cid:3)(cid:69)(cid:72)(cid:74)(cid:76)(cid:81)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:17) This ASU clarifies how certain cash receipts and cash payments
should be classified and presented in the statement of cash flows. We have made an accounting policy election
to classify distributions received from equity method investees using the nature of the distribution approach
which classifies distributions received from investees as either cash inflows from operating activities or cash
inflows from investing activities in the statement of cash flows based on the nature of the activities of the
investee that generated the distribution. The impact of adopting this ASU was not material to prior presented
periods.
We adopted the provisions of FASB ASU No. 2016-(cid:20)(cid:27)(cid:15)(cid:3)(cid:179)(cid:53)(cid:72)(cid:86)(cid:87)(cid:85)(cid:76)(cid:70)(cid:87)(cid:72)(cid:71)(cid:3)(cid:38)(cid:68)(cid:86)(cid:75)(cid:15)(cid:180)(cid:3)(cid:69)(cid:72)(cid:74)(cid:76)(cid:81)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:45)(cid:68)(cid:81)(cid:88)(cid:68)(cid:85)(cid:92)(cid:3)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:17)(cid:3) This
ASU requires amounts deemed restricted cash to be included with cash and cash equivalents when reconciling
the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, and
presentation should permit a reconciliation when cash, cash equivalents and restricted cash are presented in
more than one line item on the balance sheet. We have amounts deposited in statutory bank accounts in certain
countries to satisfy asset retirement obligations (ARO). These amounts are deemed restricted cash and are
(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:68)(cid:86)(cid:86)(cid:72)(cid:87)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:17) This standard is required to be applied
retrospectively to all periods presented, but the impact in those periods was not material.
Note 3(cid:178)Variable Interest Entities (VIEs)
We hold variable interests in VIEs that have not been consolidated because we are not considered the primary
beneficiary. Information on our significant VIEs follows:
Australia Pacific LNG Pty Ltd (APLNG)
APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with
additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we
share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities
of APLNG that most significantly impact its economic performance, which involve activities related to the
production and commercialization of coalbed methane, as well as LNG processing and export marketing. As a
result, we do not consolidate APLNG, and it is accounted for as an equity method investment.
As of December 31, 2018, we have not provided any financial support to APLNG other than amounts
previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or
purchase the assets of APLNG. See Note 6(cid:178)Investments, Loans and Long-Term Receivables, and Note 12(cid:178)
Guarantees, for additional information.
Marine Well Containment Company, LLC (MWCC)
MWCC provides well containment equipment and technology and related services in the deepwater U.S. Gulf
of Mexico. Its principal activities involve the development and maintenance of rapid-response hydrocarbon
well containment systems that are deployable in the Gulf of Mexico on a call-out basis. 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 and exercise significant influence through our
permanent seat on the ten-member Executive Committee responsible for overseeing the affairs of MWCC. In
2016, MWCC executed a $154 million term loan financing arrangement with an external financial institution
whose terms required the financing be secured by letters of credit provided by certain owners of MWCC,
including ConocoPhillips. In connection with the financing transaction, we issued a letter of credit of
$22 million which can be drawn upon in the event of a default by MWCC on its obligation to repay the
proceeds of the term loan. The fair value of this letter of credit is immaterial and not recognized on our
consolidated balance sheet. 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.
96
At December 31, 2018, the book value of our equity method investment in MWCC was $130 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.
Note 4(cid:178)Inventories
Inventories at December 31 were:
Crude oil and natural gas
Materials and supplies
Millions of Dollars
2018
432
575
1,007
$
$
2017
512
548
1,060
Inventories valued on the LIFO basis totaled $292 million and $341 million at December 31, 2018 and 2017,
respectively. The estimated excess of current replacement cost over LIFO cost of inventories was
approximately $75 million and $124 million at December 31, 2018 and December 31, 2017, respectively. In
2018, liquidation of LIFO inventory values decreased the net income attributable to ConocoPhillips by
$6 million.
Note 5(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned Dispositions
Assets Held for Sale
In 2018, we signed a definitive agreement to sell an office building for $90 million, and the held for sale
criteria were met in the fourth quarter of 2018. As of December 31, 2018, the building had a carrying value of
$90 million which we reclassified to (cid:179)(cid:51)(cid:85)(cid:72)(cid:83)(cid:68)(cid:76)(cid:71) expenses and other current (cid:68)(cid:86)(cid:86)(cid:72)(cid:87)(cid:86)(cid:180) on our consolidated balance
sheet. The transaction closed in January 2019. The building is included in our Corporate and Other segment.
2018
Assets Sold
All gains or losses on asset dispositions are reported before-(cid:87)(cid:68)(cid:91)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:42)(cid:68)(cid:76)(cid:81)(cid:3)(cid:82)(cid:81)(cid:3)
(cid:71)(cid:76)(cid:86)(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)(cid:3)(cid:3)(cid:36)(cid:79)(cid:79)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:72)(cid:71)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:68)(cid:86)(cid:75) Flows
From Investing (cid:36)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:180) section of our consolidated statement of cash flows.
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
97
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, $566 million
and $66 million for the years ended December 31, 2018, 2017 and 2016, respectively. The Barnett results of
operations are included in our Lower 48 segment.
On December 18, 2018, we completed the sale of a ConocoPhillips subsidiary to BP. The subsidiary held a
16.5 percent interest in the BP-operated Clair Field in the United Kingdom. We retained a 7.5 percent interest
in the field. At the same time, we acquired (cid:37)(cid:51)(cid:182)(cid:86) 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 16.5 percent 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 percent interest in the
Clair Field, including the recognized gain, were $748 million. The before-tax losses associated with our
16.5 percent interest in the Clair Field were $0.4 million and $8 million for the years ended December 31,
2017 and 2016, respectively. 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.
Other Planned Dispositions
In the fourth quarter of 2018, we entered into an agreement to sell our 30 percent interest in Greater Sunrise
Fields to the government of Timor-Leste for $350 million, subject to customary adjustments. The transaction
is conditional on the funding approval from the Timor-Leste government as well as regulatory approvals. The
Greater Sunrise Fields are included in our Asia Pacific and Middle East segment.
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 located adjacent to the Sabine-Neches Industrial Ship Channel
northwest of Sabine Pass, Texas. The terminal and pipeline capacity are used for receipt, storage and
regasification of LNG purchased from Qatar Liquefied Gas Company Limited (QG3) and transportation of the
regasified natural gas. As a result of entering into these agreements, we expect to recognize a loss of
approximately $60 million in the first quarter of 2019. We have also entered into agreements to amend our
contractual obligations for retaining use of the facilities. Completion of the sale is subject to regulatory
approval.
Acquisitions
In May 2018, we completed the acquisition of (cid:36)(cid:81)(cid:68)(cid:71)(cid:68)(cid:85)(cid:78)(cid:82)(cid:182)(cid:86) 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 (cid:37)(cid:51)(cid:182)(cid:86) 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 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 asset
retirement obligations, and a $100 million decrease to net working capital. The Kuparuk Assets are included in
our Alaska segment.
2017
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
98
$1.96 billion based on a price of $9.41 per share on the New York Stock Exchange. The contingent payment,
calculated and paid on a quarterly basis, is $6 million Canadian dollars (CAD) for every $1 CAD by which the
Western Canada Select (WCS) quarterly average crude price exceeds $52 CAD per barrel. Contingent
payments received during the five-year period are reflected as (cid:179)(cid:42)(cid:68)(cid:76)(cid:81) on dis(cid:83)(cid:82)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:180) on our consolidated
income statement. We reported before-tax equity earnings associated with FCCL of $197 million and
$89 million for the years ended December 31, 2017 and 2016, respectively. We reported before-tax losses of
$26 million and $572 million for the western Canada gas producing properties for the same periods,
respectively. In 2018, we recorded a gain on dispositions for these contingent payments of $95 million.
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 (cid:179)(cid:42)(cid:68)(cid:76)(cid:81) on dispositions(cid:180) 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(cid:178)
Investment in Cenovus Energy, Note 15(cid:178)Fair Value Measurement, and Note 20(cid:178)Accumulated Other
Comprehensive Loss.
In July 2017, we completed the sale of our interests in the San Juan Basin to an affiliate of Hilcorp Energy
Company for $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 million British thermal units. In 2018, we recorded a gain on dispositions
for these contingent payments of $28 million. 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 losses associated with
our interests in the San Juan Basin, including both the $3.3 billion impairment and $22 million loss on
disposition noted above, were $3.2 billion and $239 million for the years ended December 31, 2017 and 2016,
respectively. 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 before-tax losses for the
Panhandle properties of $14 million and $21 million for the years ended December 31, 2017 and 2016,
respectively. The Panhandle results were reported in our Lower 48 segment.
2016
In April 2016, we sold our interest in the Alaska Beluga River Unit natural gas field in the Cook Inlet for
$134 million, net of settlement of gas imbalances and customary adjustments, and recognized a gain on
disposition of $56 million. At the time of disposition, the net carrying value of our Beluga River Unit interest,
which was included in the Alaska segment, was $78 million, consisting primarily of $100 million of PP&E and
$19 million of AROs.
In October 2016, we completed an asset exchange with Bonavista Energy in which we gave up approximately
141,000 net acres of noncore developed properties in central Alberta in exchange for approximately 40,000 net
acres of primarily undeveloped properties in northeast British Columbia. The fair value of the transaction was
determined to be approximately $69 million and an impairment of $57 million was recognized in the third
quarter of 2016 when the assets were considered held for sale, to reduce the carrying value to fair value. A
loss on disposition of approximately $1 million was recognized upon completion of the transaction. The
divested properties were included in the Canada segment.
99
Also in October 2016, we sold ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in
three exploration blocks offshore Senegal for $442 million and recognized a gain on disposition of
$146 million. At the time of disposition, the carrying value of our interest was $286 million, which was
primarily PP&E. Senegal results of operations were reported within our Other International segment.
In November 2016, we completed the sale of our 40 percent interest in South Natuna Sea Block B for
$225 million and recognized a loss on disposition of $26 million. Our interest in Block B was included in the
Asia Pacific and Middle East segment. In 2016, we recognized an impairment of $42 million at the time it was
considered held for sale to reduce the carrying value to fair value. At the time of the disposition, the carrying
value of our interest was approximately $251 million, which included primarily $154 million of PP&E,
$178 million of accounts receivable, $25 million of inventory, $54 million of deferred tax assets, $130 million
of accounts payable and other accruals, and $38 million of employee benefit obligations.
In December 2016, we completed the sale of certain mineral and non-mineral fee lands in northeastern
Minnesota, which were included in the Lower 48 segment, for $148 million and recorded a gain on disposition
of $4 million. The majority of the assets sold were acquired during the fourth quarter of 2016 as a result of
ConocoPhillips holding a reversionary interest in the Greater Northern Iron Ore Properties Trust (the Trust), a
grantor trust that owned mineral and surface interests in the Mesabi Iron Range in northeastern Minnesota and
certain other personal property. Pursuant to the terms of the Trust Agreement, the Trust terminated on April 6,
2015. In November 2016, upon completion of the wind-down period, documents memorializing
(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182) ownership of certain Trust property, including all of the (cid:55)(cid:85)(cid:88)(cid:86)(cid:87)(cid:182)(cid:86) mineral properties and active
leases, were delivered to us and we recognized the fair value of the net assets resulting in a gain of $88 million
recorded in the (cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85) (cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:180) line on our consolidated income statement. At the time of the disposition, the
carrying value of our interests, which included the assets obtained from the Trust, consisted of $144 million of
PP&E.
Note 6(cid:178)Investments, Loans and Long-Term Receivables
(cid:3)
(cid:3)
Components of investments, loans and long-term receivables at December 31 were:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
2018
2017
Equity investments
Loans and advances(cid:178)related parties
Long-term receivables
Other investments
$
$
9,005
335
238
86
9,664
9,129
461
375
95
10,060
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2018, included:
(cid:120) APLNG(cid:178)37.5 percent owned joint venture with Origin Energy (37.5 percent) and Sinopec
(25 percent)(cid:178)to develop coalbed methane production from the Bowen and Surat basins in
Queensland, Australia, as well as process and export LNG.
(cid:120) Qatar Liquefied Gas Company Limited (3) (QG3)(cid:178)30 percent owned joint venture with affiliates of
Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)(cid:178)produces and liquefies natural
(cid:74)(cid:68)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:52)(cid:68)(cid:87)(cid:68)(cid:85)(cid:182)(cid:86)(cid:3)(cid:49)(cid:82)(cid:85)(cid:87)(cid:75)(cid:3)(cid:41)(cid:76)(cid:72)(cid:79)(cid:71)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:72)(cid:91)(cid:83)(cid:82)(cid:85)(cid:87)(cid:86)(cid:3)(cid:47)(cid:49)(cid:42)(cid:17)
100
Summarized 100 percent earnings information for equity method investments in affiliated companies,
combined, was as follows:
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Revenues
Income (loss) before income taxes
Net income (loss)
2018
2017
2016
$
11,654
3,660
3,244
11,554
(2,875)
(1,431)
10,149
660
799
Summarized 100 percent balance sheet information for equity method investments in affiliated companies,
combined, was as follows:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
2018
2017
$
3,285
41,563
2,625
23,874
2,920
42,693
2,453
25,522
Our share of income taxes incurred directly by an equity company 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, 2018, retained earnings included $27 million related to the undistributed earnings of
affiliated companies. Dividends received from affiliates were $1,226 million, $605 million and $398 million
in 2018, 2017 and 2016, respectively.
APLNG
APLNG is focused on coalbed methane 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 coalbed methane 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
(cid:87)(cid:75)(cid:72)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:82)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:182)(cid:86)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:76)(cid:83)(cid:72)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:86)(cid:92)(cid:86)(cid:87)(cid:72)(cid:80)(cid:15)(cid:3)(cid:90)(cid:75)(cid:76)(cid:79)(cid:72)(cid:3)(cid:90)(cid:72)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:47)(cid:49)(cid:42)(cid:3)(cid:73)(cid:68)(cid:70)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:17)
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, 2018, 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.
Interest payments are scheduled to commence in March 2019 and principal payments in September 2023, with
bi-annual payments due on the facility until September 2030. At December 31, 2018, a balance of $7.2 billion
was outstanding on the facilities.
101
In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata
share of the project finance facility until the project achieves financial completion. In October 2016, we
reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. In August
2017, we reached financial completion for both trains, which removed the remaining guarantee.
APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with
additional forms of subordinated financial support. See Note 3(cid:178)Variable Interest Entities (VIEs) for
additional information.
On July 1, 2016, APLNG changed its tax functional currency from Australian dollar to U.S. dollar and
translated all APLNG assets and liabilities into U.S. dollar, utilizing the exchange rate as of that date. As a
result of this change, we recorded a reduction to our investment in APLNG for the deferred tax effect of
$174 (cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)(cid:3)(cid:76)(cid:81)(cid:3)(cid:72)(cid:68)(cid:85)(cid:81)(cid:76)(cid:81)(cid:74)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:73)(cid:73)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)(cid:3)(cid:3)
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
(cid:36)(cid:54)(cid:38)(cid:3)(cid:55)(cid:82)(cid:83)(cid:76)(cid:70)(cid:3)(cid:22)(cid:21)(cid:22)(cid:15)(cid:3)(cid:179)(cid:44)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:178)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)(cid:3)(cid:48)(cid:72)(cid:87)(cid:75)(cid:82)(cid:71)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:45)(cid:82)(cid:76)(cid:81)(cid:87)(cid:3)(cid:57)(cid:72)(cid:81)(cid:87)(cid:88)(cid:85)(cid:72)(cid:86)(cid:15)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:81)(cid:3)(cid:76)(cid:80)(cid:83)(cid:68)(cid:76)rment 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
(cid:83)(cid:85)(cid:76)(cid:81)(cid:70)(cid:76)(cid:83)(cid:68)(cid:79)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:76)(cid:70)(cid:76)(cid:83)(cid:68)(cid:81)(cid:87)(cid:86)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:76)(cid:80)(cid:83)(cid:68)(cid:76)(cid:85)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:44)(cid:80)(cid:83)(cid:68)(cid:76)(cid:85)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)
income statement.
At December 31, 2018, the carrying value of our equity method investment in APLNG was $7,522 million.
The historical cost basis of our 37.5 percent share of net assets on the books of APLNG was $7,231 million,
resulting in a basis difference of $291 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 2018, 2017 and 2016 was after-tax
expense of $44 million, $100 million and $92 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(cid:178)Assets Held for Sale, Sold or
Acquired and Other Planned Dispositions and Note 7(cid:178)Investment in Cenovus Energy.
102
QG3
QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project
(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:3)(cid:70)(cid:88)(cid:85)(cid:85)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:88)(cid:87)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:7)(cid:23)(cid:25)(cid:20)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:86)(cid:3)(cid:71)(cid:72)(cid:86)(cid:70)(cid:85)(cid:76)(cid:69)(cid:72)(cid:71)(cid:3)(cid:69)(cid:72)(cid:79)(cid:82)(cid:90)(cid:3)(cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:3)(cid:179)(cid:47)(cid:82)(cid:68)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:47)(cid:82)(cid:81)(cid:74)-
(cid:55)(cid:72)(cid:85)(cid:80)(cid:3)(cid:53)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:68)(cid:69)(cid:79)(cid:72)(cid:86)(cid:17)(cid:180)(cid:3)(cid:3)(cid:36)(cid:87)(cid:3)(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)2018, the book value of our equity method investment in QG3,
excluding the project financing, was $921 million. We have terminal and pipeline use agreements with Golden
Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, in which we have a
12.4 percent interest, intended to provide us with terminal and pipeline capacity for the receipt, storage and
regasification of LNG purchased from QG3. However, currently the LNG from QG3 is being sold to markets
outside of the United States. In January 2019, we entered into agreements to sell our ownership interests in
Golden Pass LNG Terminal and Golden Pass Pipeline. For additional information, see Note 5(cid:178)Assets Held
for Sale, Sold or Acquired and Other Planned Dispositions.
Loans and Long-Term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter into
numerous agreements with other parties to pursue business opportunities. Included in such activity are loans
and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is
transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan
agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will
(cid:71)(cid:72)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:72)(cid:3)(cid:68)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:76)(cid:81)(cid:70)(cid:76)(cid:83)(cid:68)(cid:79)(cid:3)(cid:83)(cid:68)(cid:92)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:72)(cid:71)(cid:17)(cid:3)(cid:3)(cid:44)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:3)(cid:76)(cid:86)(cid:3)(cid:72)(cid:68)(cid:85)(cid:81)(cid:72)(cid:71)(cid:3)(cid:68)(cid:87)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:79)(cid:82)(cid:68)(cid:81)(cid:3)(cid:68)(cid:74)(cid:85)(cid:72)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)
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, 2018, significant loans to affiliated companies include $461 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-(cid:87)(cid:72)(cid:85)(cid:80)(cid:3)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:79)(cid:82)(cid:68)(cid:81)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:47)(cid:82)(cid:68)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:71)(cid:89)(cid:68)(cid:81)(cid:70)(cid:72)(cid:86)(cid:178)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:76)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
consolidated balance sheet, while the short-term portion is i(cid:81)(cid:3)(cid:179)(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:81)(cid:82)(cid:87)(cid:72)(cid:86)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:68)(cid:69)(cid:79)(cid:72)(cid:178)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:76)(cid:72)(cid:86)(cid:17)(cid:180)(cid:3)
Note 7(cid:178)Investment in Cenovus Energy
(cid:3)
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 approximated 16.9 percent of issued and
outstanding Cenovus Energy common stock at closing. See Note 5(cid:178)Assets Held for Sale, Sold or Acquired
and Other Planned Dispositions for additional information on the Canada disposition. At closing of the sale,
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 New York Stock Exchange.
We adopted the provisions of ASU No. 2016-01, beginning January 1, 2018, using the cumulative-effect
approach. Results for reporting periods beginning January 1, 2018, are presented under ASU No. 2016-01
with all changes in th(cid:72)(cid:3)(cid:73)(cid:68)(cid:76)(cid:85)(cid:3)(cid:89)(cid:68)(cid:79)(cid:88)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)(cid:3)(cid:86)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:85)(cid:72)(cid:73)(cid:79)(cid:72)(cid:70)(cid:87)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:68)(cid:86)(cid:75)(cid:3)(cid:41)(cid:79)(cid:82)(cid:90)(cid:86)(cid:3)(cid:41)(cid:85)(cid:82)(cid:80)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:36)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:180)(cid:3)
section of our consolidated statement of cash flows. Prior period amounts are not adjusted under the
cumulative-effect method of adopting ASU No. 2016-01. See Note 2(cid:178)Changes in Accounting Principles and
Note 20(cid:178)Accumulated Other Comprehensive Loss for the effect on our consolidated balance sheet and the
line items that have been impacted by the adoption of this standard.
103
The cumulative effect of applying the standard was the reclassification of accumulated unrealized holding
losses of $58 million, recognized in 2017, related to our investment in Cenovus Energy from accumulated
other comprehensive loss to retained earnings.
Our investment is carried at fair value of $1.46 billion as of December 31, 2018, reflecting the closing price of
Cenovus Energy shares on the New York Stock Exchange of $7.03 per share, a decrease from its fair value of
$1.90 billion at year-end 2017. For the year ended December 31, 2018, we recorded a before-tax unrealized
loss of $437 million, related to the shares held at the reporting date. See Note 15(cid:178)Fair Value Measurement,
for additional information. Subject to market conditions, we intend to decrease our investment over time
through market transactions, private agreements or otherwise.(cid:3)
Note 8(cid:178)Suspended Wells and Other Exploration Expenses
The following table reflects the net changes in suspended exploratory well costs during 2018, 2017 and 2016:
(cid:3)
(cid:3)
Millions of Dollars
2018
2017
2016
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
$
$
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:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
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
(cid:3) period greater than one year
145
711
856
2018
24
$
$
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
2017
2016
67
786
853
23
132
931
1,063
26
1,260
225
(27)
(247)
(148)
1,063
(cid:3)
104
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, 2018:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
Greater Poseidon(cid:178)Australia(2)
Barossa/Caldita(cid:178)Australia(2)
Surmont(cid:178)Canada(1)
NPRA(cid:178)Alaska(1)
Middle Magdalena Basin(cid:178)Colombia(1)
Greater Clair(cid:178)UK(2)
Bohai(cid:178)China(2)
Kamunsu East(cid:178)Malaysia(2)
NC 98(cid:178)Libya(2)
Sunrise(cid:178)Australia(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.
$
Total
2015(cid:177)2017 2012(cid:177)2014
2004(cid:177)2011
Suspended Since
177
136
108
77
65
42
19
19
15
13
40
711
-
59
18
39
65
8
19
-
-
-
5
213
165
-
56
38
-
30
-
19
11
-
18
337
12
77
34
-
-
4
-
-
4
13
17
161
In July 2016, we entered into an agreement to terminate our final Gulf of Mexico deepwater drillship contract.
The drillship, used to drill our operated deepwater well inventory in the Gulf of Mexico through April 2016,
was contracted on a shared, three-year term. Accordingly, we recorded before-tax rig cancellation charges and
third-party costs of $146 million in our Lower 48 segment in 2016.
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
(cid:179)(cid:40)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:70)ome statement and in our Other International segment in
2017.
Note 9(cid:178)Impairments
During 2018, 2017 and 2016, we recognized the following before-tax impairment charges:
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Corporate
Millions of Dollars
2018
2017
20
63
9
(79)
14
-
27
180
3,969
22
46
2,384
-
6,601
2016
1
149
88
(160)
44
17
139
$
$
105
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 United Kingdom 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.
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(cid:178)Assets Held for Sale, Sold or Acquired
and Other Planned 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 United Kingdom 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 (cid:179)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:180) section of Note 6(cid:178)Investments, Loans and
Long-Term Receivables.
(cid:55)(cid:75)(cid:72)(cid:3)(cid:70)(cid:75)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:72)(cid:71)(cid:3)(cid:69)(cid:72)(cid:79)(cid:82)(cid:90)(cid:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:40)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
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.
2016
In the Lower 48, we recorded impairments of $149 million primarily due to cancelled projects associated with
plan of development changes for Eagle Ford infrastructure, as well as lower natural gas prices and increased
ARO estimates.
In Canada, we recorded impairments of $88 million mainly due to plan of development changes, as well as
certain developed properties being written down to fair value less costs to sell.
In Europe and North Africa, we recorded a credit to impairment of $160 million, primarily in the United
Kingdom, due to decreased ARO estimates on fields at or nearing the end of life which were impaired in prior
years, partly offset by asset impairments due to lower natural gas prices in the United Kingdom.
In Asia Pacific and Middle East, we recorded impairments of $44 million, mainly due to a write-down to fair
value less costs to sell of our developed properties in Block B, offshore Indonesia, in the third quarter of 2016.
In Corporate and Other, we recorded impairments of $17 million due to cancelled projects in our Houston and
Bartlesville offices.
106
(cid:55)(cid:75)(cid:72)(cid:3)(cid:70)(cid:75)(cid:68)(cid:85)(cid:74)(cid:72)(cid:86)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:72)(cid:71)(cid:3)(cid:69)(cid:72)(cid:79)(cid:82)(cid:90)(cid:15)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:40)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
consolidated income statement and are not reflected in the table above.
Charges recorded in exploration expenses in 2016 were related to our decision announced in 2015 to reduce
deepwater exploration spending.
In our Lower 48 segment, we recorded a $203 million before-tax impairment for the associated carrying value
of our Gibson and Tiber undeveloped leaseholds in deepwater Gulf of Mexico. Additionally, we recorded a
$95 million before-tax impairment for the associated carrying value of capitalized undeveloped leasehold costs
of the Melmar prospect and a $79 million before-tax impairment, primarily as a result of changes in the
estimated market value following the completion of marketing efforts.
In our Canada segment, we recorded before-tax unproved property impairments of $31 million, primarily due
to decisions to discontinue additional testing of undeveloped leaseholds.
Note 10(cid:178)Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
(cid:3)
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."
(cid:3)
(cid:3)
$
$
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
2018
2017
7,908
178
8,086
(398)
7,688
7,798
180
7,978
(347)
7,631
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.
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.
107
During 2018 and 2017, our overall ARO changed as follows:
(cid:3)
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
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
2018
2017
$
$
7,798
348
657
(266)
(228)
(161)
(240)
7,908
8,405
358
113
(150)
(152)
(1,065)
289
7,798
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2018 and 2017, were $178 million and $180 million,
respectively.
We had accrued environmental costs of $100 million and $105 million at December 31, 2018 and 2017,
respectively, related to remediation activities in the United States and Canada. We had also accrued in
Corporate and Other $67 million and $60 million of environmental costs associated with sites no longer in
operation at December 31, 2018 and 2017, respectively. In addition, $11 million and $15 million were
included at both December 31, 2018 and 2017, 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 $88 million at December 31, 2018. The expected future undiscounted payments related to the
portion of the accrued environmental costs that have been discounted are: $6 million in 2019, $6 million in
2020, $10 million in 2021, $6 million in 2022, $2 million in 2023, and $109 million for all future years
after 2023.
108
Note 11(cid:178)Debt
(cid:3)
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
4.20% Notes due 2021
4.15% Notes due 2034
3.35% Notes due 2024
3.35% Notes due 2025
2.875% Notes due 2021
2.4% Notes due 2022
2.2% Notes due 2020
Floating rate notes due 2018 at 1.24% (cid:177) 1.75% during 2017
Floating rate notes due 2022 at 2.32% (cid:177) 3.52% during 2018
and 1.81% (cid:177) 2.32% during 2017
Industrial Development Bonds due 2018 through 2038 at 0.95% (cid:177) 1.86% during
2018 and 0.64% (cid:177) 1.74% during 2017
Marine Terminal Revenue Refunding Bonds due 2031 at 0.88% (cid:177) 1.95% during
2018 and 0.64% (cid:177) 1.74% during 2017
Other
Debt at face value
Capitalized leases
Net unamortized premiums, discounts and debt issuance costs
Total debt
Short-term debt
Long-term debt
$
Millions of Dollars
2018
2017
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
150
150
600
100
300
88
500
92
500
575
200
1,549
67
2,750
645
500
500
505
600
1,250
750
1,000
500
1,000
500
750
1,000
500
250
500
18
265
17
13,971
777
220
14,968
(112)
14,856
265
23
18,677
774
252
19,703
(2,575)
17,128
$
109
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2019 through
2023 are: $112 million, $101 million, $213 million, $935 million and $195 million, respectively.
In May 2018, we refinanced our revolving credit facility from a total aggregate principal amount of
$6.75 billion to $6.0 billion with a new 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 United States. 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,
2018 or December 31, 2017. We had no direct outstanding borrowings or letters of credit under the revolving
credit facility at December 31, 2018 or December 31, 2017. 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, 2018.
In 2018, we repaid the $250 million floating rate note due in 2018 at its natural maturity.
We also redeemed or repurchased a total $4,450 million of debt in 2018, described below, incurring
$208 million in net premiums above book value, which are repo(cid:85)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
consolidated income statement.
(cid:120) 4.20% Notes due 2021 with remaining principal of $1.0 billion.
(cid:120) 2.875% Notes due 2021 with principal of $750 million.
(cid:120) 2.4% Notes due 2022 with principal of $1.0 billion (partial repurchase of $671 million).
(cid:120) 3.35% Notes due 2024 with principal of $1.0 billion (partial repurchase of $574 million).
(cid:120) 2.2% Notes due 2020 with principal of $500 million.
(cid:120) 3.35% Notes due 2025 with principal of $500 million (partial repurchase of $301 million).
(cid:120) 4.15% Notes due 2034 with principal of $500 million (partial repurchase of $254 million).
(cid:120) 8.125% Notes due 2030 with principal of $600 million (partial repurchase of $210 million).
(cid:120) 7.8% Notes due 2027 with principal of $300 million (partial repurchase of $97 million).
(cid:120) 7.9% Notes due 2047 with principal of $100 million (partial repurchase of $40 million).
(cid:120) 9.125% Notes due 2021 with principal of $150 million (partial repurchase of $27 million).
(cid:120) 8.20% Notes due 2025 with principal of $150 million (partial repurchase of $16 million).
(cid:120) 7.65% Notes due 2023 with principal of $88 million (partial repurchase of $10 million).
At both December 31, 2018 and 2017, we had $283 million of certain variable rate demand bonds (VRDBs)
outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the
(cid:69)(cid:82)(cid:81)(cid:71)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:3)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:92)(cid:3)(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:71)(cid:68)(cid:92)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:57)(cid:53)(cid:39)(cid:37)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:47)(cid:82)(cid:81)(cid:74)-(cid:87)(cid:72)(cid:85)(cid:80)(cid:3)(cid:71)(cid:72)(cid:69)(cid:87)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)
balance sheet.
During 2013, a lease of a semi-submersible floating production system (FPS) commenced for the Gumusut
development, located in Malaysia, in which we are a co-venturer. The FPS lease provides for an initial
noncancelable term of 15 years, a subsequent 5-year cancelable term with no required lease payments, and an
110
additional 5-year term with terms and conditions to be agreed at a later date. The lease has no ongoing
purchase options or escalation clauses. Adjustments to provisional contingent rental payments may occur due
to the finalization of actual commissioning costs. The lease does not impose any significant restrictions
concerning dividends, debt or further leasing activities.
A capital lease asset and capital lease obligation were recognized for our proportionate interest in the FPS of
$906 million, based on the present value of the future minimum lease payments using our before-tax
incremental borrowing rate of 3.58 percent for debt with similar terms. Our proportionate interest in the FPS is
29 percent as of December 31, 2018. The net carrying value of the capital lease asset was approximately
$353 million and $434 million as of December 31, 2018 and 2017, respectively. The capital lease asset is
being depreciated over a period consistent with the estimated proved reserves of Gumusut using the unit-of-
(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:80)(cid:72)(cid:87)(cid:75)(cid:82)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:86)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:71)(cid:72)(cid:83)(cid:85)(cid:72)(cid:70)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:39)(cid:72)(cid:83)(cid:85)(cid:72)(cid:70)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:71)(cid:72)(cid:83)(cid:79)(cid:72)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:80)(cid:82)(cid:85)(cid:87)(cid:76)(cid:93)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:180)(cid:3)
line on our consolidated income statement. As of December 31, 2018 and 2017, accumulated depreciation of
the capital lease asset amounted to approximately $462 million and $381 million, respectively.
At December 31, 2018, future minimum payments due under capital leases were:
(cid:3)
2019
2020
2021
2022
2023
Remaining years
Total
Less: portion representing imputed interest
Capital lease obligations
Note 12(cid:178)Guarantees
(cid:3)
(cid:3)
$
$
Millions
of Dollars
118
116
100
98
87
453
972
(195)
777
At December 31, 2018, 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, 2018, 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
2018 exchange rates:
(cid:120) 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 12 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, 2018, the carrying value of this guarantee is approximately $14 million.
111
(cid:120)
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 23 years. Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated to be $800 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.
(cid:120) We have guaranteed the performance of APLNG with regard to certain other contracts executed in
(cid:70)(cid:82)(cid:81)(cid:81)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:77)(cid:72)(cid:70)(cid:87)(cid:182)(cid:86)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:71)(cid:3)(cid:71)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:74)(cid:88)(cid:68)(cid:85)(cid:68)(cid:81)(cid:87)(cid:72)(cid:72)(cid:86)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:85)(cid:72)(cid:80)(cid:68)(cid:76)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:72)(cid:85)(cid:80)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:88)(cid:83)(cid:3)(cid:87)(cid:82)(cid:3)
27 years or the life of the venture. Our maximum potential amount of future payments related to these
guarantees is approximately $140 million and would become payable if APLNG does not perform.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately
$780 million, which consist primarily of guarantees of the residual value of leased office buildings, guarantees
(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:88)(cid:68)(cid:79)(cid:3)(cid:89)(cid:68)(cid:79)(cid:88)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:79)(cid:72)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:70)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:68)(cid:76)(cid:85)(cid:70)(cid:85)(cid:68)(cid:73)(cid:87)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:3)(cid:74)(cid:88)(cid:68)(cid:85)(cid:68)(cid:81)(cid:87)(cid:72)(cid:72)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:77)(cid:82)(cid:76)(cid:81)(cid:87)(cid:3)(cid:89)(cid:72)(cid:81)(cid:87)(cid:88)(cid:85)(cid:72)(cid:182)(cid:86)(cid:3)(cid:83)(cid:85)(cid:82)(cid:77)(cid:72)(cid:70)(cid:87)(cid:3)
finance reserve accounts. These guarantees have remaining terms of up to four 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.
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, 2018, was approximately $90 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, 2018, were approximately $30 million of environmental accruals
(cid:73)(cid:82)(cid:85)(cid:3)(cid:78)(cid:81)(cid:82)(cid:90)(cid:81)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:68)(cid:80)(cid:76)(cid:81)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:86)(cid:86)(cid:72)(cid:87)(cid:3)(cid:85)(cid:72)(cid:87)(cid:76)(cid:85)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:69)(cid:79)(cid:76)(cid:74)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:70)(cid:70)(cid:85)(cid:88)(cid:72)(cid:71)(cid:3)(cid:72)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:3)
(cid:70)(cid:82)(cid:86)(cid:87)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:17)(cid:3)(cid:3)(cid:41)(cid:82)(cid:85)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:69)(cid:82)(cid:88)(cid:87)(cid:3)environmental liabilities, see
Note 13(cid:178)Contingencies and Commitments.
In 2012, we completed the separation of our downstream business, creating two independent energy
companies: ConocoPhillips and Phillips 66. On March 1, 2015, a supplier to one of the refineries included in
Phillips 66 as part of the separation of our downstream businesses formally registered Phillips 66 as a party to
the supply agreement, thereby triggering a guarantee we provided at the time of separation. As of
December 31, 2017, the carrying value of this guarantee was $98 million. Because Phillips 66 has indemnified
us for losses incurred under this guarantee, we also recorded an indemnification asset from Phillips 66 of
$98 million. During the third quarter of 2018, a termination agreement between the supplier and Phillips 66
was executed, releasing all parties from their respective obligations under the supply agreement. Since all
obligations under the supply agreement were satisfied and discharged, the guarantee was terminated. As of
December 31, 2018, the carrying value of this guarantee and the associated indemnification asset have been
removed.
112
Note 13(cid:178)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(cid:178)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
(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:85)(cid:71)(cid:3)(cid:68)(cid:70)(cid:70)(cid:85)(cid:88)(cid:68)(cid:79)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:72)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:3)(cid:79)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)
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
(cid:72)(cid:91)(cid:83)(cid:72)(cid:85)(cid:76)(cid:72)(cid:81)(cid:70)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:85)(cid:72)(cid:80)(cid:72)(cid:71)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:68)(cid:80)(cid:76)(cid:81)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:86)(cid:76)(cid:87)(cid:72)(cid:86)(cid:15)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:76)(cid:72)(cid:86)(cid:182)(cid:3)(cid:70)(cid:79)(cid:72)(cid:68)(cid:81)(cid:88)(cid:83)(cid:3)(cid:72)(cid:91)(cid:83)(cid:72)(cid:85)(cid:76)(cid:72)(cid:81)(cid:70)(cid:72)(cid:15)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:71)(cid:68)(cid:87)(cid:68)(cid:3)(cid:85)(cid:72)(cid:79)(cid:72)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)
the U.S. Environmental Protection Agency (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
113
sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have
not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional
environmental assessments, cleanups and proceedings. See Note 10(cid:178)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, 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, 2018, we had performance obligations secured by letters of credit of
$323 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 (cid:74)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86) Nationalization Decree. As a result, (cid:57)(cid:72)(cid:81)(cid:72)(cid:93)(cid:88)(cid:72)(cid:79)(cid:68)(cid:182)(cid:86) national oil company,
Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over (cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)
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
World (cid:37)(cid:68)(cid:81)(cid:78)(cid:182)(cid:86) International Centre for Settlement of Investment Disputes (ICSID). On September 3, 2013, an
ICSID arbitration tribunal held that Venezuela unlawfully expropriated (cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182) significant oil
investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation
was unlawful. A separate arbitration phase is currently proceeding to determine the damages owed to
ConocoPhillips for (cid:57)(cid:72)(cid:81)(cid:72)(cid:93)(cid:88)(cid:72)(cid:79)(cid:68)(cid:182)(cid:86) actions.
In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the International
Chamber of Commerce (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. By
year-end 2018, we collected from PDVSA under the settlement and recognized in other income $430 million
before-tax consisting of $230 million from the sale of commodity inventory and $200 million in cash. The
remainder of the initial payments will become an adjustment to a future quarterly installment. Per the
settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips
114
agreed to suspend its legal enforcement actions, including in the Dutch Caribbean. ConocoPhillips has
ensured that the settlement meets all appropriate U.S. regulatory requirements, including 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. This ICC arbitration is currently in
progress.
In February 2017, the ICSID tribunal unanimously awarded Burlington Resources, Inc., a wholly owned
subsidiary of ConocoPhillips, $380 (cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:40)(cid:70)(cid:88)(cid:68)(cid:71)(cid:82)(cid:85)(cid:182)(cid:86)(cid:3)(cid:88)(cid:81)(cid:79)(cid:68)(cid:90)(cid:73)(cid:88)(cid:79)(cid:3)(cid:72)(cid:91)(cid:83)(cid:85)(cid:82)(cid:83)(cid:85)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:37)(cid:88)(cid:85)(cid:79)(cid:76)(cid:81)(cid:74)(cid:87)(cid:82)(cid:81)(cid:182)(cid:86)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:3)
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 $24 million contribution from
Perenco Ecuador Limited, its co-venturer and consortium operator, pursuant to a joint and several liability
provision in the joint operating agreement (JOA). (cid:40)(cid:70)(cid:88)(cid:68)(cid:71)(cid:82)(cid:85)(cid:182)(cid:86)(cid:3)(cid:72)(cid:81)(cid:89)(cid:76)(cid:85)(cid:82)(cid:81)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:73)(cid:85)(cid:68)(cid:86)(cid:87)(cid:85)(cid:88)(cid:70)(cid:87)(cid:88)(cid:85)(cid:72)(cid:3)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:72)(cid:85)(cid:70)(cid:79)(cid:68)(cid:76)(cid:80)(cid:86)(cid:3)
against Perenco remain pending in a separate ICSID arbitration between Perenco and Ecuador, and Burlington
may owe Perenco contribution under the JOA for damages found by this tribunal.
In December 2016, ConocoPhillips Angola filed a notice of arbitration against Sonangol E.P. under the
Block 36 Production Sharing Contract relating to disputes arising thereunder. In 2018, the parties reached a
confidential settlement.
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. This
arbitration is ongoing.
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 tribunal was constituted in February 2018. The
arbitration is ongoing.
In 2017 and 2018, cities, counties, a state government, and a trade association in California, New York,
(cid:58)(cid:68)(cid:86)(cid:75)(cid:76)(cid:81)(cid:74)(cid:87)(cid:82)(cid:81)(cid:15)(cid:3)(cid:53)(cid:75)(cid:82)(cid:71)(cid:72)(cid:3)(cid:44)(cid:86)(cid:79)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:48)(cid:68)(cid:85)(cid:92)(cid:79)(cid:68)(cid:81)(cid:71)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:51)(cid:68)(cid:70)(cid:76)(cid:73)(cid:76)(cid:70)(cid:3)(cid:38)(cid:82)(cid:68)(cid:86)(cid:87)(cid:3)(cid:41)(cid:72)(cid:71)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:86)(cid:75)(cid:72)(cid:85)(cid:80)(cid:72)(cid:81)(cid:182)(cid:86)(cid:3)(cid:36)(cid:86)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)
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.
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. ConocoPhillips will vigorously defend against these lawsuits.
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
(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:68)(cid:74)(cid:74)(cid:85)(cid:72)(cid:74)(cid:68)(cid:87)(cid:72) amounts of estimated payments under these various agreements are:
2019(cid:178)$7 million; 2020(cid:178)$7 million; 2021(cid:178)$7 million; 2022(cid:178)$7 million; 2023(cid:178)$7 million; and 2024 and
after(cid:178)$61 million. Total payments under the agreements were $39 million in 2018, $43 million in 2017 and
$42 million in 2016.
115
Note 14(cid:178)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
natural gas liquids.
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 normal purchase
normal sale 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
2018
410
40
370
30
2017
275
36
282
28
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
2018
2017
2016
$
45
7
(41)
77
-
(61)
(198)
(1)
161
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)
2018
2017
(17)
(1)
(29)
12
116
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
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
$
Millions of Dollars
2018
2017
7
-
6
-
1
6
-
15
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 losses from foreign currency exchange derivatives incurred and the line item where they appear on our
consolidated income statement were:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
Foreign currency transaction losses
$
1
13
247
2018
2017
2016
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*
Sell Canadian dollar, buy U.S. dollar
*Primarily euro and Norwegian krone.
In Millions
Notional Currency
2018
2017
USD
GBP
CAD
805
21
1,242
-
1
1,225
Financial Instruments
We invest excess cash in financial instruments with maturities based on our cash forecasts for the various
currency pools we manage. The maturities of these investments may from time to time extend beyond
90 days. The types of financial instruments that we currently invest include:
(cid:120) Time deposits: Interest bearing deposits placed with approved financial institutions.
(cid:120) Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or
government agency purchased at a discount to mature at par.
(cid:120) Government or government agency obligations: Short-term securities issued by the U.S. government
or U.S. government agencies.
117
(cid:55)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:86)(cid:87)(cid:85)(cid:88)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:83)(cid:83)(cid:72)(cid:68)(cid:85)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:68)(cid:86)(cid:75)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:89)(cid:68)(cid:79)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:3)(cid:76)(cid:73)(cid:3)
the maturities at the time we made the investments were 90 days or less; otherwise, these financial instruments
(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:54)(cid:75)(cid:82)(cid:85)(cid:87)-(cid:87)(cid:72)(cid:85)(cid:80)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:17)
Cash
Time Deposits
Remaining maturities from 1 to 90 days
Commercial Paper
Remaining maturities from 1 to 90 days
Remaining maturities from 91 to 180 days
Government Obligations
Remaining maturities from 1 to 90 days
Millions of Dollars
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
2018
876
2017
948
3,509
5,004
229
-
1,301
5,915
373
-
-
6,325
$
$
2018
2017
-
248
-
-
248
821
978
74
-
1,873
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents,
short-term investments, over-the-counter (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 and time deposits with major international banks and financial
institutions.
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 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.
118
The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were
in a liability position on December 31, 2018 and December 31, 2017, was $62 million and $55 million,
respectively. For these instruments, no collateral was posted as of December 31, 2018 or December 31, 2017.
If our credit rating had been downgraded below investment grade on December 31, 2018, we would be
required to post $62 million of additional collateral, either with cash or letters of credit.
Note 15(cid:178)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:
(cid:120) Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
(cid:120) Level 2: Inputs other than quoted prices that are directly or indirectly observable.
(cid:120) 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. At the end
of the fourth quarter of 2017, our $1,899 million investment in Cenovus Energy was transferred from Level 2 to
Level 1 due to the lapsing of trading restrictions. There were no other material transfers in or out of Level 1
during 2018 or 2017.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in
Cenovus Energy shares 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 New York Stock Exchange. 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 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
(cid:85)(cid:72)(cid:79)(cid:72)(cid:89)(cid:68)(cid:81)(cid:87)(cid:3)(cid:72)(cid:70)(cid:82)(cid:81)(cid:82)(cid:80)(cid:76)(cid:70)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:88)(cid:86)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:76)(cid:81)(cid:83)(cid:88)(cid:87)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:80)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:69)(cid:72)(cid:86)(cid:87)(cid:3)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:73)(cid:68)(cid:76)(cid:85)(cid:3)(cid:89)(cid:68)(cid:79)(cid:88)(cid:72)(cid:17)(cid:3)(cid:3)
Level 3 activity was not material for all periods presented.
119
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, 2018
Level 1 Level 2 Level 3
December 31, 2017
Level 1 Level 2 Level 3 Total
Total
Millions of Dollars
Assets
Investment in Cenovus Energy $ 1,462
Commodity derivatives
236
$ 1,698
Total assets
-
181
181
Liabilities
Commodity derivatives
Total liabilities
$
$
225
225
145
145
-
33
33
30
30
1,462
450
1,912
1,899
175
2,074
-
106
106
-
30
30
1,899
311
2,210
400
400
158
158
111
111
41
41
310
310
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
offset exists.
Millions of Dollars
Gross
Amounts
Recognized
Gross
Amounts
Offset
Net
Gross Amounts
Amounts
Presented Collateral
Cash
without
Right of Setoff
Net
Amounts
December 31, 2018
Assets
Liabilities
December 31, 2017
Assets
Liabilities
$
$
450
400
311
310
280
280
186
186
170
120
125
124
-
10
-
7
9
4
4
5
161
106
121
112
At December 31, 2018 and December 31, 2017, we did not present any amounts gross on our consolidated
balance sheet where we had the right of setoff.
120
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:
Year ended December 31, 2018
Net PP&E (held for sale)
March 31, 2018
September 30, 2018
Year ended December 31, 2017
Net PP&E (held for use)
December 31, 2017
Net PP&E (held for sale)
June 30, 2017
December 31, 2017
Equity method investments
June 30, 2017
Millions of Dollars
Fair Value
Measurements Using
Fair Value
Level 1
Inputs
Level 3
Inputs
Before-Tax
Loss
250
201
-
201
250
-
44
43
75
2,830
113
7,656
-
2,830
113
75
-
-
154
3,882
78
-
7,656
2,384
$
$
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(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned
Dispositions.
Net PP&E (held for use)
Net PP&E held for use is comprised of various producing properties impaired to their individual fair values.
The fair values were determined by internal discounted cash flow models using estimates of future production,
prices from futures exchanges and pricing service companies, costs, and a discount rate believed to be
consistent with those used by principal market participants.
Equity Method Investments
During 2017, our investment in APLNG was written down to its fair value of $7,656 million, resulting in a
before-tax-charge of $2,384 million. For additional information on APLNG, see Note 6(cid:178)Investments, Loans
and Long-Term Receivables.
Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
(cid:120) Cash and cash equivalents and short-term investments: The carrying amount reported on the balance
sheet approximates fair value.
(cid:120) 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(cid:178)related parties.
Investment in Cenovus Energy shares: See Note 7(cid:178)Investment in Cenovus Energy for a discussion of
the carrying value and fair value of our investment in Cenovus Energy shares.
(cid:120)
121
(cid:120) Loans and advances(cid:178)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(cid:178)Investments, Loans and Long-Term
Receivables, for additional information.
(cid:120) 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.
(cid:120) 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
Total loans and advances(cid:178)related parties
Financial liabilities
Total debt, excluding capital leases
Commodity derivatives
Millions of Dollars
Carrying Amount
Fair Value
2018
2017
2018
2017
$
1,462
170
468
14,191
110
1,899
125
586
1,462
170
468
18,929
117
16,147
110
1,899
125
586
22,435
117
Commodity Derivatives
At December 31, 2018, commodity derivative assets and liabilities appear net with no obligations to return
cash collateral and $10 million of rights to reclaim cash collateral, respectively. At December 31, 2017,
commodity derivative assets and liabilities appear net with no obligations to return cash collateral and
$7 million of rights to reclaim cash collateral, respectively.
Note 16(cid:178)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
2018
2017
2016
1,785,419,175
6,218,259
1,791,637,434
1,782,079,107
3,340,068
1,785,419,175
1,778,226,388
3,852,719
1,782,079,107
608,312,034
44,976,179
653,288,213
544,809,771
63,502,263
608,312,034
542,230,673
2,579,098
544,809,771
Preferred Stock
We have authorized 500 million shares of preferred stock, par value $.01 per share, none of which was issued
or outstanding at December 31, 2018 or 2017.
122
Noncontrolling Interests
At December 31, 2018 and 2017, we had $125 million and $194 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
On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock through 2019.
On March 29, 2017, we announced plans to repurchase an additional $3 billion of common stock through
2019. On July 12, 2018, we announced an authorization of an additional $9 billion for share repurchases
bringing the total program authorization to $15 billion. Repurchase of shares began in November 2016, and
totaled 111,057,540 shares at a cost of $6.1 billion, through December 31, 2018.(cid:3)
Note 17(cid:178)Non-Mineral Leases
The company primarily leases drilling equipment and office buildings, as well as ocean transport vessels,
tugboats, barges, corporate aircraft and other facilities and equipment. Certain leases include escalation
clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or
options to purchase the leased property for the fair market value at the end of the lease term. There are no
significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or
borrowing ability. For additional information on leased assets under capital leases, see Note 11(cid:178)Debt.
At December 31, 2018, future minimum rental payments due under noncancelable leases were:
(cid:3)
(cid:3)
(cid:3)
2019
2020
2021
2022
2023
Remaining years
Total
Less: income from subleases
Net minimum operating lease payments
Operating lease rental expense for the years ended December 31 was:
(cid:3)
(cid:3)
$
$
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
Millions
of Dollars
248
425
136
319
54
212
1,394
(7)
1,387
(cid:3)
(cid:3)
Total rentals
Less: sublease rentals
2018
2017
2016
$
$
253
(16)
237
264
(20)
244
537
(10)
527
(cid:3)
123
Note 18(cid:178)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:
(cid:3) (cid:3)
(cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
Millions of Dollars
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
Pension Benefits
2018
U.S.
2017
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
Other Benefits
2018
2017
$
$
$
$
$
$
3,236
83
99
-
-
(44)
(507)
(4)
(730)
3
-
2,136
3,845
81
107
2
7
(259)
(143)
(3)
-
-
(199)
3,438
3,416
89
118
-
-
244
(631)
-
-
-
-
3,236
3,445
77
103
2
-
52
(117)
-
-
-
283
3,845
1,969
3,066
3,076
3,404
2,541
(112)
144
-
(507)
(730)
-
1,336
(800)
3,647
(106)
156
2
(143)
-
(198)
3,358
(80)
2,081
336
755
-
(631)
-
-
2,541
(695)
3,068
313
114
2
(117)
-
267
3,647
(198)
265
1
8
22
-
(10)
(67)
-
-
-
(1)
218
-
-
45
22
(67)
-
-
-
(218)
286
2
9
23
-
12
(68)
-
-
-
1
265
-
-
45
23
(68)
-
-
-
(265)
124
Millions of Dollars
Pension Benefits
2018
2017
Other Benefits
2018
2017
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Noncurrent assets
Current liabilities
Noncurrent liabilities
Total recognized
$
$
-
(59)
(741)
(800)
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
4.25 %
4.00
3.80 %
5.80
4.00
232 (cid:3)
(4)(cid:3)
(308)(cid:3)
(80)(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
3.05 (cid:3)
3.65 (cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
2.90 (cid:3)
4.30 (cid:3)
3.75 (cid:3)
-
(38)
(657)
(695)
205
(4)
(399)
(198)
-
(44)
(174)
(218)
-
(45)
(220)
(265)
3.55
4.00
2.80
3.75
4.05
-
3.30
-
3.80
6.55
4.00
3.00 (cid:3)
5.05 (cid:3)
3.85
3.30
-
-
3.60
-
-
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
2018
2017
Other Benefits
2018
2017
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
Unrecognized net actuarial (gain) loss
Unrecognized prior service cost (credit)
$
516
-
310
(4)
588
-
358
(16)
(21)
(216)
(12)
(249)
125
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Sources of Change in Other
(cid:3) Comprehensive Income (Loss)
Net gain (loss) arising during the period
Amortization of (gain) loss included in
(cid:3) income (loss)*
Net change during the period
(cid:3)
Prior service credit (cost) arising during the
period
Amortization of prior service cost (credit)
(cid:3) included in income (loss)
Net change during the period
*Includes settlement losses recognized in 2018 and 2017.
Millions of Dollars
Pension Benefits
2018
2017
Other Benefits
2018
2017
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
$
(177)
249
72
-
-
-
$
$
$
17
31
48
(7)
(5)
(12)
(40)
71
200
160
50
121
10
(1)
9
(12)
(3)
(15)
-
4
4
2
(6)
(4)
-
-
(35)
(35)
(36)
(36)
Included in accumulated other comprehensive loss at December 31, 2018, were the following before-tax
amounts that are expected to be amortized into net periodic benefit cost during 2019:
Millions of Dollars
Pension
Benefits
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
Other
Benefits
Unrecognized net actuarial (gain) loss
Unrecognized prior service credit
$
52
-
31
(2)
(2)
(33)
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 $4,110 million,
$3,768 million, and $3,702 million, respectively, at December 31, 2018, and $5,634 million, $5,226 million,
and $5,113 million, respectively, at December 31, 2017.
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and
the accumulated benefit obligation were $586 million and $504 million, respectively, at December 31, 2018,
and were $578 million and $503 million, respectively, at December 31, 2017.
126
(cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
(cid:3) (cid:3)
U.S.
2016
2018
2018
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17) U.S.
Other Benefits
Millions of Dollars
Pension Benefits
2017
The components of net periodic benefit cost of all defined benefit plans are presented in the following table:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Components of Net
(cid:3) Periodic Benefit Cost
Service cost
Interest cost
Expected return on plan
(cid:3) assets
Amortization of prior
(cid:3) service cost (credit)
Recognized net actuarial
(cid:3) loss (gain)
Settlements
Curtailment loss
Net periodic benefit cost
69
131
-
279
53
196
-
317
(1)
-
-
(27)
(3)
-
-
(28)
86
202
14
399
50
-
-
66
31
-
-
59
26
-
-
69
76
120
(149) (147)
77
103
89
118
81
107
108
133
83
99
2017
(158)
(132)
(114)
(155)
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
1
8
2
9
(35)
(36)
(6)
(5)
(6)
4
(cid:3)
(cid:3)
-
-
-
$
$
5
2
13
-
(34)
(2)
-
1
(20)
2016
(cid:55)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:82)(cid:81)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:83)(cid:72)(cid:85)(cid:76)(cid:82)(cid:71)(cid:76)(cid:70)(cid:3)(cid:69)(cid:72)(cid:81)(cid:72)(cid:73)(cid:76)(cid:87)(cid:3)(cid:70)(cid:82)(cid:86)(cid:87)(cid:15)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:68)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:72)(cid:85)(cid:89)(cid:76)(cid:70)(cid:72)(cid:3)(cid:70)(cid:82)(cid:86)(cid:87)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:82)(cid:81)(cid:72)(cid:81)(cid:87)(cid:15)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)
(cid:72)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:76)(cid:87)(cid:72)(cid:80)(cid:3)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 $196 million in 2018, $131 million in 2017, and $202 million in
2016 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.
As part of the 2016 restructuring program, we concluded that actions taken during the year resulted in a
significant reduction of future services of active employees primarily in the U.S. qualified pension plan and a
U.S. nonqualified supplemental retirement plan. As a result, we recognized an increase in the benefit
obligation and a proportionate share of prior service cost from other comprehensive income (loss) as a
curtailment loss of $15 million during the year ended December 31, 2016.
Also, as part of the 2016 restructuring program in the United States and Europe, we recognized expense for
special termination benefits of $15 million during the year ended December 31, 2016, consisting of
$14 million in the United States and $1 million in Europe.
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.
127
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
2019 that declines to 5 percent by 2024. The measurement of the U.S. post-65 retiree medical accumulated
postretirement benefit obligation assumes an ultimate health care cost trend rate of 5 percent achieved in 2019.
A one-percentage-point change in the assumed health care cost trend rate would be immaterial to
ConocoPhillips.
Plan Assets(cid:178)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 39 percent equity
securities, 54 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, 2018 and 2017.
(cid:120) 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.
(cid:120) 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.
(cid:120) 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.
(cid:120) Fair values of mutual funds are based on quoted market prices, which represent the net asset value of
shares held.
(cid:120) Time deposits are valued at cost, which approximates fair value.
(cid:120) 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.
(cid:120) 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.
(cid:120) Fair values of insurance contracts are valued at the present value of the future benefit payments owed
(cid:69)(cid:92)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:76)(cid:81)(cid:86)(cid:88)(cid:85)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:83)(cid:79)(cid:68)(cid:81)(cid:86)(cid:182)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:76)(cid:70)(cid:76)(cid:83)(cid:68)(cid:81)(cid:87)(cid:86)(cid:17)
(cid:120) 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.
(cid:120) 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, 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
128
benefit obligation covered by the contract. At December 31, 2017, the participating interest in the
annuity contract was valued at $99 million and consisted of $265 million in debt securities, less
$166 million for the accumulated benefit obligation covered by the contract. The net change from
2017 to 2018 is due to a decrease in the fair value of the underlying investments of $37 million offset
by a decrease in the present value of the contract obligation of $22 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:
2018
Equity securities
(cid:3) U.S.
(cid:3) International
(cid:3) Mutual funds
Debt securities
(cid:3) Government
(cid:3) Corporate
(cid:3) Mutual funds
Cash and cash equivalents
Time deposits
Derivatives
Real estate
(cid:3)
Total in fair value hierarchy
Millions of Dollars
U.S.
International
Level 1 Level 2 Level 3
Total Level 1 Level 2 Level 3
Total
$
$
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
-
-
-
-
-
-
-
-
-
124
124
371
241
394
889
-
363
71
6
(17)
124
2,442
-
-
-
$
364
Investments measured at net asset value*
Equity securities
Common/collective trusts
Debt securities
Corporate
Agency and mortgage-backed 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 value of $84 million and net receivables related to
security transactions of $16 million.
-
-
-
-
-
2,137
-
-
548
5
80
1,249
-
-
-
-
-
181
-
-
-
-
-
124
-
-
-
-
-
230
-
-
641
-
109
3,345
-
-
-
-
-
20
-
-
-
-
-
2
153
$
-
-
-
129
The fair values of our pension plan assets at December 31, by asset class were as follows:
2017
Equity securities
(cid:3) U.S.
(cid:3) International
(cid:3) Mutual funds
Debt securities
(cid:3) Government
(cid:3) Corporate
(cid:3) Mutual funds
Cash and cash equivalents
Time deposits
Derivatives
Real estate
(cid:3)
Total in fair value hierarchy
Millions of Dollars
U.S.
International
Level 1 Level 2 Level 3
Total Level 1 Level 2 Level 3
Total
$
$
161
178
146
-
-
-
-
-
-
-
485
-
-
-
-
2
-
-
-
-
-
2
14
-
-
-
-
-
-
-
-
-
14
175
178
146
-
2
-
-
-
-
-
501
440
315
292
902
-
144
111
3
5
-
2,212
-
-
165
-
-
-
-
-
-
-
165
-
-
-
-
-
-
-
-
-
123
123
440
315
457
902
-
144
111
3
5
123
2,500
-
-
-
$
805
Investments measured at net asset value*
Equity securities
Common/collective trusts
Debt securities
Corporate
Agency and mortgage-backed 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 value of $99 million and net payables related to security
transactions of $14 million.
-
-
-
-
-
2,212
-
-
1,042
17
74
2,439
-
-
-
-
-
485
-
-
-
-
-
165
-
-
-
-
-
123
172
15
648
24
94
3,636
-
-
-
-
-
14
-
-
-
-
-
2
183
$
-
-
-
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 2019, we expect to contribute approximately
$195 million to our domestic qualified and nonqualified pension and postretirement benefit plans and
$185 million to our international qualified and nonqualified pension and postretirement benefit plans.
130
The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract
and which reflect expected future service, as appropriate, are expected to be paid:
Millions of Dollars
Pension
Benefits
U.S.
(cid:44)(cid:81)(cid:87)(cid:182)(cid:79)(cid:17)
Other
Benefits
2019
2020
2021
2022
2023
2024(cid:177)2027
$
400
251
232
222
216
880
123
129
137
138
143
788
36
34
30
27
24
69
Severance Accrual
As a result of staff reductions occurring throughout the year, severance accruals of $70 million were recorded
in 2018. The following table summarizes our severance accrual activity for the year ended December 31,
2018:
Balance at December 31, 2017
Accruals
Benefit payments
Foreign currency translation adjustments
Balance at December 31, 2018
Millions of Dollars
$
$
53
70
(73)
(2)
48
Of the remaining balance at December 31, 2018, $23 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 34 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 will be 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 2018, $77 million in 2017, and
$58 million in 2016.
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 $31 million in 2018, $35 million in 2017, and $44 million in 2016.
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
131
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
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-(cid:72)(cid:80)(cid:83)(cid:79)(cid:82)(cid:92)(cid:72)(cid:72)(cid:3)(cid:71)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:90)(cid:75)(cid:82)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:76)(cid:69)(cid:88)(cid:87)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:71)(cid:3)
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(cid:178)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
2018
265
64
$
2017
227
76
2016
272
92
Stock Options(cid:178)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 and 2016 were measured on the date of grant using the
Black-Scholes-Merton option-pricing model. The weighted-average assumptions used were as follows:
(cid:3)
Assumptions used
Risk-free interest rate
Dividend yield
Volatility factor
Expected life (years)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
2017
(cid:3)
2.24 (cid:1081)(cid:3)
4.00 (cid:1081)(cid:3)
28.12 (cid:1081)(cid:3)
6.39 (cid:3)
2016
1.55
4.00
26.80
6.37
There were no ranges in the assumptions used to determine the fair market values of our options granted in
2017 and 2016.
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 and 2016, expected volatility was based on the
132
weighted-average blend of the compa(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:75)(cid:76)(cid:86)(cid:87)(cid:82)(cid:85)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:72)(cid:3)(cid:89)(cid:82)(cid:79)(cid:68)(cid:87)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:48)(cid:68)(cid:92)(cid:3)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:21)(cid:3)(cid:11)(cid:87)(cid:75)(cid:72)(cid:3)(cid:71)(cid:68)(cid:87)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)
separation of our 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, 2018:
Outstanding at December 31, 2017
Exercised
Forfeited
Expired or cancelled
Outstanding at December 31, 2018
Vested at December 31, 2018
Exercisable at December 31, 2018
(cid:3)
Options
24,722,803
(3,903,130)
(84,694)
(1,355,302) (cid:3)
19,379,677 (cid:3)
18,820,388 (cid:3)
16,213,002 (cid:3)
Weighted-Average
Exercise Price
Millions of Dollars
Aggregate
Intrinsic Value
$
$
$
$
52.18
45.71
58.23
60.53 (cid:3)
52.88 (cid:3)
53.16 (cid:3)
54.89 (cid:3)
$
$
$
$
177
94
214
204
152
The weighted-average remaining contractual term of outstanding options, vested options and exercisable
options at December 31, 2018, was 5.16 years, 5.09 years and 4.69 years, respectively. The weighted-average
grant date fair value of stock option awards granted during 2017 and 2016 was $9.18 and $5.39, respectively.
The aggregate intrinsic value of options exercised was $4 million in 2017 and zero in 2016.
During 2018, we received $178 million in cash and realized a tax benefit of $18 million from the exercise of
options. At December 31, 2018, the remaining unrecognized compensation expense from unvested options
was $2 million, which will be recognized over a weighted-average period of 0.87 years, the longest period
being 1.12 years.
Stock Unit Program(cid:178)Generally, restricted stock units are granted annually under the provisions of the Plan
and vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock
units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual
installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc
to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest
vary by award.
Stock-Settled
Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per
unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not issued as common stock until the earlier of separation from the company or the end of the regularly
scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a quarterly
cash payment of a dividend equivalent that is charged to retained earnings. The grant date fair market value of
these restricted stock units is deemed equal to the average ConocoPhillips stock price on the grant date. The
grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal
to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will
not be received.
133
The following summarizes our stock-settled stock unit activity for the year ended December 31, 2018:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Outstanding at December 31, 2017
Granted
Forfeited
Issued
Outstanding at December 31, 2018
Not Vested at December 31, 2018
7,826,852
2,465,100
(173,265)
(2,571,714)
7,546,973
5,090,209
45.75
52.45
45.72
Grant Date Fair Value
(cid:3)
Weighted-Average Millions of Dollars
Total Fair Value
43.41
43.69
Stock Units
154
$
$
$
(cid:3)
At December 31, 2018, the remaining unrecognized compensation cost from the unvested stock-settled units
was $88 million, which will be recognized over a weighted-average period of 1.68 years, the longest period
being 2.76 years. The weighted-average grant date fair value of stock unit awards granted during 2017 and
2016 was $48.77 and $32.15, respectively. The total fair value of stock units issued during 2017 and 2016 was
$159 million and $191 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, 2018:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Outstanding at December 31, 2017
Granted
Forfeited
Issued
Outstanding at December 31, 2018
Not Vested at December 31, 2018
-
393,571
(3,849)
(13,114)
376,608
90,254
Grant Date Fair Value
62.21
62.21
53.68
59.17
(cid:3)
Weighted-Average Millions of Dollars
Total Fair Value
Stock Units
-
$
1
$
$
(cid:3)
(cid:3)
At December 31, 2018, the remaining unrecognized compensation cost from the unvested cash-settled units
was $3 million, which will be recognized over a weighted-average period of 1.79 years, the longest period
being 2.12 years.
134
Performance Share Program(cid:178)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 employ(cid:72)(cid:72)(cid:182)(cid:86)(cid:3)(cid:86)(cid:72)(cid:83)(cid:68)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:3)(cid:82)(cid:85)(cid:3)(cid:73)(cid:76)(cid:89)(cid:72)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:86)(cid:3)(cid:68)(cid:73)(cid:87)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:74)(cid:85)(cid:68)(cid:81)(cid:87)(cid:3)(cid:71)(cid:68)(cid:87)(cid:72)(cid:3)(cid:11)(cid:68)(cid:79)(cid:87)(cid:75)(cid:82)(cid:88)(cid:74)(cid:75)(cid:3)(cid:85)(cid:72)(cid:70)(cid:76)(cid:83)(cid:76)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)
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, 2018:
Outstanding at December 31, 2017
Granted
Forfeited
Issued
Outstanding at December 31, 2018
Not Vested at December 31, 2018
(cid:3)
Weighted-Average
Grant Date Fair Value
(cid:3)
(cid:3)
Millions of Dollars
Total Fair Value
$
$
$
50.79
53.28
48.89
50.45
48.41
$
29
Stock Units
2,753,465
19,708
(2,859)
(434,772)
2,335,542
58,914
At December 31, 2018, 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 2017 and 2016 was $49.76 and $33.13, respectively. The total fair value of stock-settled PSUs issued
during 2017 and 2016 was $57 million and $17 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
135
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
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, 2018:
Outstanding at December 31, 2017
Granted
Forfeited
Settled
Outstanding at December 31, 2018
Not Vested at December 31, 2018
(cid:3)
Weighted-Average
Grant Date Fair Value
(cid:3)
(cid:3)
Millions of Dollars
Total Fair Value
$
$
$
55.19
53.28
59.17
62.21
62.21
$
22
Stock Units
1,214,533
321,965
(9,282)
(396,209)
1,131,007
87,900
At December 31, 2018, the remaining unrecognized compensation cost from unvested cash-settled
performance share awards was $1 million, which will be recognized over a weighted-average period of
0.89 years, the longest period being 1.13 years. The weighted-average grant date fair value of cash-settled
PSUs granted during 2017 and 2016 was $49.76 and $33.13, respectively. The total fair value of cash-settled
performance share awards settled during 2017 and 2016 was $24 million and $31 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(cid:178)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
(cid:73)(cid:82)(cid:85)(cid:80)(cid:72)(cid:85)(cid:3)(cid:80)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:37)(cid:82)(cid:68)(cid:85)(cid:71)(cid:3)(cid:82)(cid:73)(cid:3)(cid:39)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:82)(cid:85)(cid:3)(cid:68)(cid:86)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:81)(cid:3)(cid:72)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:72)(cid:81)(cid:86)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:3)(cid:87)(cid:75)(cid:68)(cid:87)(cid:3)
has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or
dividend equivalent.
136
The following summarizes the aggregate activity of these restricted shares and units for the year ended
December 31, 2018:
Outstanding at December 31, 2017
Granted
Cancelled
Issued
Outstanding at December 31, 2018
Not Vested at December 31, 2018
(cid:3)
Weighted-Average
Grant Date Fair Value
(cid:3)
(cid:3)
Millions of Dollars
Total Fair Value
$
45.77
62.01
23.09
$
46.57
$
17
Stock Units
1,301,040
70,922
(1,334)
(263,313)
1,107,315
-
At December 31, 2018, 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 2017 and 2016 was $48.87 and $40.36, respectively. The total fair value of awards issued
during 2017 and 2016 was $4 million and $2 million, respectively.
Note 19(cid:178)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
2018
2017
2016
4
545
79
(3,046)
(9)
(1,634)
3,273
(166)
108
(96)
3,668
1,729
(510)
51
(125)
(1,822)
393
(519)
(135)
(67)
(1,971)
$
$
137
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components
of deferred tax liabilities and assets at December 31 were:
Millions of Dollars
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
2018
8,004
60
61
156
8,281
641
2,891
104
330
2,378
398
6,742
(3,040)
3,702
4,579
$
$
2017
9,692
61
178
464
10,395
786
3,060
57
166
2,310
152
6,531
(1,254)
5,277
5,118
At December 31, 2018, noncurrent assets and liabilities included deferred taxes of $442(cid:3)million and
$5,021 million, respectively. At December 31, 2017, noncurrent assets and liabilities included deferred taxes
of $164(cid:3)million and $5,282 million, respectively.
At December 31, 2018, 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
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
$
$
1,016
364
312
686
2,378
17
364
32
647
1,060
2027
2036-2038
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 2018, valuation allowances increased a total of $1,786 million. The increase
primarily relates to deferred tax assets recognized during 2018 as a result of the U.S. Tax Cuts and Jobs Act
(Tax Legislation), as further discussed below, and are related to U.S. tax basis and foreign tax credits
associated with our foreign branch assets that we do not expect to realize. Based on our historical taxable
income, expectations for the future, and available tax-planning strategies, management expects deferred tax
assets, net of valuation allowance, will primarily be realized as offsets to reversing deferred tax liabilities.
138
At December 31, 2018, unremitted income considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures totaled approximately $3,808 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 $190 million.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2018,
2017 and 2016:
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
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
2018
882
268
43
(73)
(35)
(4)
1,081 (cid:3)
$
$
2017
381
612
109
(129)
(5)
(86)
882
2016
459
32
19
(118)
(9)
(2)
381
Included in the balance of unrecognized tax benefits for 2018, 2017 and 2016 were $1,081 million,
$882 million and $359 million, respectively, which, if recognized, would impact our effective tax rate. The
balance of the unrecognized tax benefits increased in 2018 mainly due to the treatment of distributions from
certain of 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.
At December 31, 2018, 2017 and 2016, accrued liabilities for interest and penalties totaled $45 million,
$54 million and $54 million, respectively, net of accrued income taxes. Interest and penalties resulted in a
benefit to earnings of $4 million in 2018, no impact to earnings in 2017, and a benefit to earnings of
$18 million in 2016.
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: United Kingdom (2015), Canada (2010), United States (2014)
and Norway (2017). Issues in dispute for audited years and audits for subsequent years are ongoing and in
various stages of completion in the many jurisdictions in which we operate around the world. Consequently,
the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably
possible such changes could be significant when compared with our total unrecognized tax benefits, but the
amount of change is not estimable.
139
The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal
statutory rate with the provision for income taxes, were:
Income (loss) before income taxes
(cid:3) United States
$
(cid:3) 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
Enhanced oil recovery credit
U.K. rate change
Other
(cid:3)
(cid:3)
(cid:3)
$
Millions of Dollars
2018
2017
Percent of Pre-Tax Income (Loss)
2016
2018
2017
2016
2,867
7,106
9,973
2,095
1,766
(10)
-
(150)
(21)
(4)
(26)
-
135
(99)
-
(18)
3,668 (cid:3)
(5,250)
2,635
(2,615)
(915)
625
(852)
(1,277)
-
(962)
881
-
834
(84)
(68)
-
(4)
(1,822)
(4,410)
(1,120)
(5,530)
(1,936)
361
-
-
-
(60)
55
-
-
(122)
(62)
(161)
(46)
(1,971)
28.7 %
71.3
100.0 %
200.8
(100.8)
100.0
79.7
20.3
100.0
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
35.0
(6.5)
-
-
-
1.1
(1.0)
-
-
2.2
1.1
2.9
0.8
35.6
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 ConocoPhillips subsidiary to BP. The
subsidiary held a 16.5 percent interest in the BP-operated Clair Field in the United Kingdom. The disposition
generated a before-tax gain of $715 million with no associated tax cost. See Note 5(cid:178)Assets Held for Sale,
Sold or Acquired and Other Planned Dispositions for additional information on the U.K. disposition.
Tax Legislation was enacted in the United States 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.
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 have now 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.
140
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. At December 31, 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(cid:178)Assets Held for Sale, Sold or Acquired and Other Planned
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 (cid:179)(cid:36)(cid:51)(cid:47)(cid:49)(cid:42)(cid:180) section of Note 6(cid:178)Investments, Loans and Long-Term Receivables, for information on the
impairment of our APLNG investment.
The decrease in the effective tax rate for 2016 was primarily due to our mix of income among taxing
jurisdictions, reduced net tax benefit from the tax law changes discussed below, and the absence of a tax
benefit associated with electing the fair market value method of apportioning interest expense for prior years.
In the United Kingdom, legislation was enacted on September 15, 2016, to decrease the overall U.K. upstream
corporation tax rate from 50 percent to 40 percent effective January 1, 2016. As a result, we recorded a
$161 million net tax benefit related to the remeasurement of our U.K. deferred tax balance in 2016.
Certain operating losses in jurisdictions outside of the United States only yield a tax benefit in the United
States as a worthless security deduction. For 2018, 2017 and 2016, before consideration of unrecorded tax
benefits discussed above, the amount of the tax benefit was $36 million, $962 million and $60 million,
respectively.
141
Note 20(cid:178)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, 2015
Other comprehensive income (loss)
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
$
*See Note 2—Changes in Accounting Principles for additional information.
(443)
(104)
(547)
147
(400)
39
-
(361)
-
-
-
(58)
(58)
-
58
-
(5,804)
158
(5,646)
586
(5,060)
(642)
-
(5,702)
(6,247)
54
(6,193)
675
(5,518)
(603)
58
(6,063)
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
2018
189
50
$
$
2017
135
74
142
Note 21(cid:178)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 (Receipts)
Interest
Income taxes
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased
Short-term investments sold
*See Note 5(cid:178)Assets Held for Sale, Sold, or Acquired and Other Planned Dispositions.
**2016 is net of $585 million related to refunds received from the Internal Revenue Service.
Millions of Dollars
2018
2017
2016
$
395
(37)
(1,017)
(44)
42
15
1,907
(9)
7
40
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
$
$
772
2,976
1,163
1,168
1,151
(318) **
(1,953)
3,573
1,620
(6,617)
4,827
(1,790)
(1,753)
1,702
(51)
The following items are included in in the (cid:179)(cid:38)(cid:68)(cid:86)(cid:75) Flows from Operating (cid:36)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:180) section of our consolidated
cash flows.
In 2018, we collected $430 million from PDVSA consisting of $230 million from the sale of commodity
inventory and $200 million in cash, as partial payments 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(cid:178)Contingencies and Commitments.
We made discretionary payments to our domestic qualified pension plan of $120 million and $600 million in
2018 and 2017, respectively.
In 2017, we recognized a $180 million adverse cash impact from the settlement of cross-currency swap
transactions.
143
Note 22(cid:178)Other Financial Information
(cid:3)
Interest and Debt Expense
Incurred
(cid:3) Debt
(cid:3) Other
Capitalized
Expensed
Other Income
Interest income
Other, net
(cid:3)
(cid:3)
Research and Development Expenditures(cid:178)expensed
(cid:3)
$
$
$
$
$
(cid:3)
(cid:3)
Millions of Dollars
2018
2017
2016
1,114
103
1,217
(119)
1,098
112
417
529
100
(cid:3)
(cid:3)
1,279
123
1,402
(157)
1,245
57
198
255
116
838
67
905
(170)
735
97 (cid:3)
76 (cid:3)
173 (cid:3)
(cid:3)
78 (cid:3)
(cid:3)
1,075 (cid:3)
Shipping and Handling Costs*
*Amounts included in production and operating expenses. 2017 and 2016 have been reclassified to conform to the current-period presentation
resulting from the adoption of ASU No. 2017-07. See Note 2—Changes in Accounting Principles, for additional information.
1,050
$
1,140
Foreign Currency Transaction (Gains) Losses(cid:178)after-tax
Alaska
Lower 48
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
(cid:3)
(cid:3)
$
$
(cid:3)
- (cid:3)
- (cid:3)
(11) (cid:3)
(26) (cid:3)
3 (cid:3)
- (cid:3)
21 (cid:3)
(13) (cid:3)
-
-
3
7
23
1
(3)
31
-
-
1
(7)
(9)
7
(18)
(26)
Millions of Dollars
2018
2017
Properties, Plants and Equipment
Proved properties
Unproved properties
Other
Gross properties, plants and equipment
Less: Accumulated depreciation, depletion and amortization
Net properties, plants and equipment
144
4,662
5,278
$ 100,657 102,044
4,491
3,896
110,597 110,431
(64,748)
45,683
(64,899)
$ 45,698
Note 23(cid:178)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
2018
2017
2016
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.
107
99
59
(13)
98
98
60
(14)
133
101
63
(12)
$
The table above includes transactions with the FCCL Partnership through the date of the sale. See Note 6(cid:178)
Investments, Loans and Long-Term Receivables, for additional information.
Note 24(cid:178)Sales and Other Operating Revenues
Transitional Arrangements
We adopted the provisions of ASC Topic 606 beginning January 1, 2018, using the modified retrospective
approach, which we have applied to contracts within the scope of the standard that had not been completed as
of January 1, 2018. Results for reporting periods beginning after January 1, 2018, are presented under ASC
Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with ASC
Topic 605. See Note 2(cid:178)Changes in Accounting Principles for the effect on our consolidated balance sheet
and the line items which have been impacted by the adoption of this standard.
The cumulative effect of applying the standard relates solely to certain licensing arrangements where revenue
was previously recognized ($61 million in 2011, $146 million in 2015, and $44 million in 2017) based on
contractual milestones. Under ASC Topic 606, such revenues are recognized when the customer has the
ability to utilize and benefit from its right to use the license. As a result, such historically recognized revenues
must be reversed through a cumulative effect adjustment and deferred until such time when the customer has
the ability to utilize and benefit from the license. The cumulative effect adjustment relates to contracts that
were not substantially completed at the date of implementation.
Practical Expedients(cid:3)(cid:3)
Typically, our commodity sales contracts are less than 12 months in duration; however, certain commodity
sales contracts may carry a longer duration, which may extend 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.
145
Revenue from Contracts with Customers(cid:3)
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
*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.
$
Millions of Dollars
2018
2017 *
2016 *
$
28,098
20,525
16,527
8,218
101
36,417
8,669
(88)
29,106
7,278
(112)
23,693
Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at
(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:72)(cid:86)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:84)(cid:88)(cid:68)(cid:79)(cid:76)(cid:73)(cid:92)(cid:3)(cid:68)(cid:86)(cid:3)(cid:71)(cid:72)(cid:85)(cid:76)(cid:89)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:86)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:3)(cid:36)(cid:54)(cid:38)(cid:3)(cid:55)(cid:82)(cid:83)(cid:76)(cid:70)(cid:3)(cid:27)(cid:20)(cid:24)(cid:15)(cid:3)(cid:179)(cid:39)(cid:72)(cid:85)(cid:76)(cid:89)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:43)(cid:72)(cid:71)(cid:74)(cid:76)(cid:81)(cid:74)(cid:15)(cid:180)(cid:3)
and for which we have not elected normal purchases and normal sales (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(cid:178)Segment Disclosures and Related Information:
Millions of Dollars
2018
2017 *
2016 *
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
*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.
6,358
629
1,231
8,218
$
$
6,302
864
1,503
8,669
5,391
813
1,074
7,278
Millions of Dollars
2018
2017 *
2016 *
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
Natural gas
Other
Physical contracts meeting the definition of a derivative
*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.
1,112
6,734
372
8,218
$
$
588
7,811
270
8,669
436
6,502
340
7,278
Receivables and Contract Liabilities
Receivables from Contracts with Customers
(cid:36)(cid:87)(cid:3)(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:15)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:81)(cid:82)(cid:87)(cid:72)(cid:86)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:68)(cid:69)(cid:79)(cid:72)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:79)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:86)(cid:75)(cid:72)(cid:72)(cid:87)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)
trade receivables of $2,889 million compared with $2,675 million at December 31, 2017, 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
146
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 January 1, 2018
Contractual payments received
Revenue recognized
At December 31, 2018
Amounts Recognized in the Consolidated Balance Sheet at December 31, 2018
Current liabilities
Noncurrent liabilities
Millions of Dollars
$
$
$
$
251
103
(148)
206
169
37
206
(cid:39)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:7)(cid:20)(cid:23)(cid:27)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:54)(cid:68)(cid:79)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:86)(cid:180)(cid:3)(cid:79)(cid:76)(cid:81)(cid:72)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
consolidated income statement. We expect to recognize the contract liabilities as of December 31, 2018, as
revenue between the remainder of 2019 and 2022 as construction is completed.
(cid:51)(cid:85)(cid:76)(cid:82)(cid:85)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:68)(cid:71)(cid:82)(cid:83)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:36)(cid:54)(cid:38)(cid:3)(cid:55)(cid:82)(cid:83)(cid:76)(cid:70)(cid:3)(cid:25)(cid:19)(cid:25)(cid:15)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:88)(cid:68)(cid:79)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:83)(cid:68)(cid:92)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:85)(cid:72)(cid:70)(cid:72)(cid:76)(cid:89)(cid:72)(cid:71)(cid:3)(cid:90)(cid:72)(cid:85)(cid:72)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:74)(cid:81)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:179)(cid:54)(cid:68)(cid:79)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:86)(cid:180)(cid:3)(cid:90)(cid:75)(cid:72)(cid:81)(cid:3)(cid:85)(cid:72)ceived.
Note 25(cid:178)Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids 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(cid:178)Accounting Policies. Intersegment sales are at
prices that approximate market.
147
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
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
2018
2017
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
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
(cid:3)
$
$
$
$
2016
3,681
10,719
(17)
10,702
2,192
(218)
1,974
3,462
3,705
169
23,693
868
4,358
975
1,253
1,606
1
140
9,201
In 2018, sales by our Lower 48, Alaska and Canada segments to a certain refining company accounted for
approximately $4 billion or 11 percent of our total consolidated sales and other operating revenues.
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
148
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
2018
2017
2016
(cid:3)
(cid:3)
$
(cid:3)
$
(cid:3)
$
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
$
(cid:3)
$
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
$
$
$
(cid:3)
(cid:3)
6
1
-
16
1,051
-
-
1,074
(cid:3)
376
474
(96)
2,265
722
30
(103)
3,668
(cid:3)
1,814 (cid:3)
1,747 (cid:3)
63 (cid:3)
1,866 (cid:3)
2,070 (cid:3)
364 (cid:3)
(1,667) (cid:3)
6,257
86
378
-
55
8,821
-
-
9,340
(cid:3)
(cid:3)
7
5
197
10
553
-
-
772
(cid:3)
(689)
(2,453)
(616)
1,165
351
21
399
(1,822)
(cid:3)
1,466
(2,371)
2,564
553
(1,098)
167
(2,136)
(855)
56
402
-
55
9,077
-
-
9,590
9
(6)
89
22
(51)
-
(11)
52
(59)
(1,328)
(383)
(46)
306
(40)
(421)
(1,971)
319
(2,257)
(935)
394
209
(16)
(1,329)
(3,615)
58
426
8,784
62
11,611
-
4
20,945
149
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
(cid:3) Corporate
(cid:3) Lower 48
(cid:3) Europe and North Africa
(cid:3) Asia Pacific and Middle East
(cid:3) Other International
Interest and debt expense
(cid:3) Corporate
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
2018
2017
14,648 (cid:3)
14,888 (cid:3)
5,748 (cid:3)
9,883 (cid:3)
16,151 (cid:3)
89 (cid:3)
8,573 (cid:3)
69,980 (cid:3)
1,298
3,184
477
877
718
6
190
6,750
80
-
2
15
-
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
101
-
2
9
-
2016
12,314
22,673
17,548
11,727
20,451
97
4,962
89,772
883
1,262
698
1,020
838
104
64
4,869
47
-
2
8
-
735
1,098
1,245
19,571
10,720
1,114
5,012
36,417
13,260
10,773
1,102
3,971
29,106
10,801
9,401
837
2,654
23,693
$
$
$
$
$
$
$
$
150
Geographic Information
(cid:3)
Millions of Dollars
(cid:3)
(cid:3)
Sales and Other Operating Revenues(1)
Long-Lived Assets(2)
2018
2017
2016
2018
2017
2016
$
United States
Australia(3)
Canada
China
Indonesia
Libya(4)
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 investments in and advances to affiliated companies.
(3)Includes amounts related to the joint petroleum development area with shared ownership held by Australia and Timor-Leste.
(4)Included in “Other foreign countries” in prior periods.
17,204
1,448
2,619
712
757
586
1,103
2,348
2,248
81
29,106
14,400
1,353
1,974
551
938
-
735
1,645
1,816
281
23,693
22,740
1,798
2,024
836
886
1,142
1,346
2,886
2,606
153
36,417
23,623
9,657
5,613
1,275
758
699
2,736
6,154
3,335
1,423
55,273
26,838
9,301
5,333
1,380
669
679
2,327
5,582
1,583
1,346
55,038
$
32,949
12,259
16,846
1,372
856
704
3,323
6,228
3,209
1,530
79,276
Note 26(cid:178)New Accounting Standards
In February 2016, the FASB issued ASU No. 2016-02, (cid:179)(cid:47)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:180) (ASU No. 2016-02), which establishes
comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU
supersedes the existing requirements in FASB ASC Topic 840, (cid:179)(cid:47)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:180) (FASB ASC Topic 840), and requires
lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of
ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement,
presentation and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for
interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted.
Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional
practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or
entered into after the earliest comparative period presented in the financial statements.
ASU No. 2016-02 was amended in January 2018 by the provisions of ASU No. 2018-01, (cid:179)(cid:47)(cid:68)(cid:81)(cid:71) Easement
Practical Expedient for Transition to Topic (cid:27)(cid:23)(cid:21)(cid:180) (ASU No. 2018-01), and in July 2018 by the provisions of
ASU No. 2018-10, (cid:179)(cid:38)(cid:82)(cid:71)(cid:76)(cid:73)(cid:76)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81) Improvements to Topic 842, (cid:47)(cid:72)(cid:68)(cid:86)(cid:72)(cid:86)(cid:180) (ASU No. 2018-10). In addition, ASU
No. 2016-02 was further amended in July 2018 by the provisions of ASU No. 2018-11, (cid:179)(cid:55)(cid:68)(cid:85)(cid:74)(cid:72)(cid:87)(cid:72)(cid:71)
(cid:44)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180) (ASU No. 2018-11), and in December 2018 by the provisions of ASU No. 2018-20, (cid:179)(cid:49)(cid:68)(cid:85)(cid:85)(cid:82)(cid:90)-
Scope Improvements for (cid:47)(cid:72)(cid:86)(cid:86)(cid:82)(cid:85)(cid:86)(cid:180) (ASU No. 2018-20).
ASU No. 2018-11 sets forth certain additional practical expedients for lessors and provides entities with an
option to apply the provisions of ASU No. 2016-02, as amended, to leasing arrangements existing at or entered
into after the (cid:36)(cid:54)(cid:56)(cid:182)(cid:86) effective date of adoption (the (cid:179)(cid:50)(cid:83)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79) Transition (cid:48)(cid:72)(cid:87)(cid:75)(cid:82)(cid:71)(cid:180)(cid:12)(cid:17) Entities that elect to utilize
the Optional Transition Method would not apply the provisions of ASU No. 2016-02, as amended, to
comparative periods presented in the financial statements.
We plan to adopt ASU No. 2016-02, as amended, effective January 1, 2019, utilizing the Optional Transition
Method. Accordingly, the comparative periods presented in the financial statements prior to January 1, 2019,
will be presented pursuant to the existing requirements of FASB ASC Topic 840 and not be adjusted upon the
adoption of the ASU. We also expect to utilize the package of optional transition-related practical expedients
set forth by ASU No. 2016-02, as amended, which permit entities to not reassess upon the adoption of the ASU
151
certain historical conclusions regarding lease contract identification and classification, as well as the historical
accounting treatment of initial direct costs (the (cid:179)(cid:51)(cid:68)(cid:70)(cid:78)(cid:68)(cid:74)(cid:72) of Optional Practical (cid:40)(cid:91)(cid:83)(cid:72)(cid:71)(cid:76)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180)(cid:12)(cid:17) For lease
arrangements containing both lease and non-lease components, we will adopt the optional practical expedient
to not separate lease components from non-lease components for all new or modified leases executed on or
after the effective date of the ASU, subject to making any elections for leases after the effective date in new
asset classes. Furthermore, we do not expect to record assets and liabilities on our consolidated balance sheet
for new or existing lease arrangements with terms of 12 months or less.
The expected impact of the adoption of ASU No. 2016-02, as amended, relates primarily to our balance sheet,
resulting from the initial recognition of lease liabilities and corresponding right-of-use assets for our existing
population of operating leases, as well as enhanced disclosure of our leasing arrangements. We expect to
recognize on our consolidated balance sheet approximately $1 billion of operating lease liabilities and
corresponding right-of-use assets upon the adoption of ASU No. 2016-02, as amended. We have implemented
a third-party lease accounting software solution to facilitate the ongoing accounting and financial reporting
requirements of the ASU and also expect the adoption of the ASU to result in certain changes being made to
our existing accounting policies and systems, business processes, and internal controls.
While our evaluation of ASU No. 2016-02, as amended, and related implementation activities approach
completion, we continue to monitor proposals issued by the FASB to clarify the ASU.
In June 2016, the FASB issued ASU No. 2016-13, (cid:179)(cid:48)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87) of Credit Losses on Financial (cid:44)(cid:81)(cid:86)(cid:87)(cid:85)(cid:88)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:180)
(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, and early adoption of the
standard is permitted. Entities are required to adopt ASU No. 2016-13 using a modified retrospective
approach, subject to certain limited exceptions. We are currently evaluating the impact of the adoption of this
ASU.
152
Oil and Gas Operations (Unaudited)
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification
Topic (cid:28)(cid:22)(cid:21)(cid:15)(cid:3)(cid:179)(cid:40)(cid:91)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:36)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:178)(cid:50)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:68)(cid:86)(cid:15)(cid:180)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:56)(cid:17)(cid:54)(cid:17)(cid:3)(cid:54)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:40)(cid:91)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:3)
Commission (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
(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)(cid:3)(cid:68)(cid:73)(cid:73)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:72)(cid:86)(cid:182)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:68)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:86)(cid:72)(cid:74)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86). 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.
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 production sharing contracts (PSCs), which are
(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:72)(cid:71)(cid:3)(cid:88)(cid:81)(cid:71)(cid:72)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:72)(cid:70)(cid:82)(cid:81)(cid:82)(cid:80)(cid:76)(cid:70)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:180)(cid:3)(cid:80)(cid:72)(cid:87)(cid:75)(cid:82)(cid:71)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:68)(cid:86)(cid:3)(cid:89)(cid:68)(cid:85)(cid:76)(cid:68)(cid:69)(cid:79)(cid:72)-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, 2018,
approximately 6 percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East
geographic reporting area, and 5 percent of our total proved reserves were under a variable-royalty regime,
located in our Canada geographic reporting area.
Our reserves disclosures by geographic area include the United States, Canada, Europe (Norway and the
United Kingdom), Asia Pacific/Middle East, and Africa.
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(cid:178)from a given date
forward, from known reservoirs, and under existing economic conditions, operating methods, and government
regulations(cid:178)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.
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
(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:88)(cid:81)(cid:76)(cid:87)(cid:86)(cid:3)(cid:68)(cid:85)(cid:82)(cid:88)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:90)(cid:82)(cid:85)(cid:79)(cid:71)(cid:17)(cid:3)(cid:3)(cid:36)(cid:86)(cid:3)(cid:83)(cid:68)(cid:85)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:15)(cid:3)(cid:72)(cid:68)(cid:70)(cid:75)(cid:3)(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:88)(cid:81)(cid:76)(cid:87)(cid:182)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)
153
processes and controls are revi(cid:72)(cid:90)(cid:72)(cid:71)(cid:3)(cid:68)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:79)(cid:92)(cid:3)(cid:69)(cid:92)(cid:3)(cid:68)(cid:81)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:87)(cid:72)(cid:68)(cid:80)(cid:3)(cid:90)(cid:75)(cid:76)(cid:70)(cid:75)(cid:3)(cid:76)(cid:86)(cid:3)(cid:75)(cid:72)(cid:68)(cid:71)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:85)(cid:3)
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
(cid:83)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80)(cid:3)(cid:72)(cid:81)(cid:74)(cid:76)(cid:81)(cid:72)(cid:72)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:88)(cid:79)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:73)(cid:76)(cid:85)(cid:80)(cid:15)(cid:3)(cid:85)(cid:72)(cid:89)(cid:76)(cid:72)(cid:90)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:88)(cid:81)(cid:76)(cid:87)(cid:86)(cid:182)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:68)(cid:71)(cid:75)(cid:72)(cid:85)(cid:72)(cid:81)(cid:70)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:54)(cid:40)(cid:38)(cid:3)(cid:74)(cid:88)(cid:76)(cid:71)(cid:72)(cid:79)(cid:76)(cid:81)(cid:72)(cid:86)(cid:3)
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 2018, our processes and controls used to assess over 90 percent of proved reserves as of December 31,
2018, 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
(cid:68)(cid:70)(cid:70)(cid:82)(cid:85)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:54)(cid:40)(cid:38)(cid:3)(cid:85)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:3)(cid:3)(cid:44)(cid:81)(cid:3)(cid:86)(cid:88)(cid:70)(cid:75)(cid:3)(cid:85)(cid:72)(cid:89)(cid:76)(cid:72)(cid:90)(cid:15)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:87)(cid:72)(cid:70)(cid:75)(cid:81)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:73)(cid:73)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:39)(cid:9)(cid:48)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:81)(cid:3)
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
(cid:70)(cid:85)(cid:76)(cid:87)(cid:72)(cid:85)(cid:76)(cid:68)(cid:17)(cid:3)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:3)(cid:85)(cid:72)(cid:87)(cid:68)(cid:76)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:39)(cid:9)(cid:48)(cid:3)(cid:87)(cid:82)(cid:3)(cid:85)(cid:72)(cid:89)(cid:76)(cid:72)(cid:90)(cid:3)(cid:76)(cid:87)(cid:86)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:86)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:3)(cid:82)(cid:69)(cid:77)(cid:72)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)
third-(cid:83)(cid:68)(cid:85)(cid:87)(cid:92)(cid:3)(cid:76)(cid:81)(cid:83)(cid:88)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:86)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:86)(cid:17)(cid:3)(cid:3)(cid:39)(cid:9)(cid:48)(cid:182)(cid:86)(cid:3)(cid:82)(cid:83)(cid:76)(cid:81)(cid:76)(cid:82)(cid:81)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:74)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:86)(cid:86)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)ntrols
employed by ConocoPhillips in estimating its December 31, 2018, proved reserves for the properties reviewed
(cid:68)(cid:85)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:85)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:54)(cid:40)(cid:38)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:71)(cid:72)(cid:73)(cid:76)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:3)(cid:3)(cid:39)(cid:9)(cid:48)(cid:182)(cid:86)(cid:3)(cid:85)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:76)(cid:86)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:71)(cid:3)(cid:68)(cid:86)(cid:3)(cid:40)(cid:91)(cid:75)(cid:76)(cid:69)(cid:76)(cid:87)(cid:3)(cid:28)(cid:28)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)
Report on Form 10-K.
The technical person primarily responsible for overseeing the processes and internal controls used in the
(cid:83)(cid:85)(cid:72)(cid:83)(cid:68)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:86)(cid:3)(cid:76)(cid:86)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:53)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:79)(cid:76)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:17)(cid:3)(cid:3)This
individual holds a (cid:80)(cid:68)(cid:86)(cid:87)(cid:72)(cid:85)(cid:182)(cid:86) 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 United States and several
international field locations.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the (cid:179)(cid:38)(cid:85)(cid:76)(cid:87)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)
(cid:36)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:40)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:86)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:39)(cid:76)(cid:86)(cid:70)(cid:88)(cid:86)(cid:86)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:36)(cid:81)(cid:68)(cid:79)(cid:92)(cid:86)(cid:76)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:53)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)
of Operations for additional discussion of the sensitivities surrounding these estimates.
154
Proved Reserves
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Total company
End of 2015
End of 2016
End of 2017
End of 2018
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Crude Oil
Millions of Barrels
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Africa
Total
915
(57)
6
-
33
(60)
-
837
113
6
-
41
(60)
-
937
72
2
233
48
(59)
-
1,233
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
588
(93)
3
-
79
(71)
-
506
65
-
-
210
(64)
(10)
707
(90)
-
1
179
(82)
(12)
703
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,503
(150)
9
-
112
(131)
-
1,343
178
6
-
251
(124)
(10)
1,644
(18)
2
234
227
(141)
(12)
1,936
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
14
3
-
-
-
(3)
(1)
13
1
-
-
-
(1)
(12)
1
2
-
-
2
(1)
-
4
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
346
-
-
-
-
(43)
-
303
38
-
-
-
(45)
-
296
24
-
-
2
(40)
(36)
246
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
203
6
7
-
7
(35)
(3)
185
32
-
-
2
(34)
-
185
6
-
-
1
(33)
-
159
93
-
-
-
-
(5)
-
88
-
-
-
-
(5)
-
83
-
-
-
-
(5)
-
78
204
-
-
-
-
(1)
-
203
-
-
-
-
(7)
-
196
5
-
-
-
(13)
-
188
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,270
(141)
16
-
119
(213)
(4)
2,047
249
6
-
253
(211)
(22)
2,322
19
2
234
232
(228)
(48)
2,533
93
-
-
-
-
(5)
-
88
-
-
-
-
(5)
-
83
-
-
-
-
(5)
-
78
915
837
937
1,233
588
506
707
703
1,503
1,343
1,644
1,936
14
13
1
4
346
303
296
246
296
273
268
237
204
203
196
188
2,363
2,135
2,405
2,611
155
Years Ended
December 31
Developed
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Undeveloped
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Africa
Total
Crude Oil
Millions of Barrels
819
747
828
1,058
283
256
315
346
1,102
1,003
1,143
1,404
-
-
-
-
96
90
109
175
-
-
-
-
-
-
-
-
305
250
392
357
-
-
-
-
-
-
-
-
401
340
501
532
-
-
-
-
13
13
1
2
-
-
-
-
1
-
-
2
-
-
-
-
200
184
190
192
-
-
-
-
146
119
106
54
-
-
-
-
139
106
121
113
204
203
196
185
1,658
1,509
1,651
1,896
93
88
83
78
64
79
64
46
-
-
-
-
-
-
-
-
-
-
-
3
-
-
-
-
93
88
83
78
612
538
671
637
-
-
-
-
Notable changes in proved crude oil reserves in the three years ended December 31, 2018, included:
(cid:120) Revisions: 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. In 2016, revisions in Lower 48 and Alaska were primarily due to lower prices.
(cid:120) Purchases: In 2018, Alaska purchases were due to the Kuparuk Assets and Western North Slope acquisitions.
(cid:120) Extensions and discoveries: 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. In 2016,
extensions and discoveries in Alaska were primarily due to drilling success in the Western North Slope, and extensions
and discoveries in Lower 48 were primarily due to continued drilling success in Eagle Ford and Bakken.
(cid:120) Sales: In 2018, Europe sales were due to the disposition of a subsidiary that held a 16.5 percent interest in the Clair
Field in the United Kingdom. In 2017, 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 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Total company
End of 2015
End of 2016
End of 2017
End of 2018
Natural Gas Liquids
Millions of Barrels
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
114
(3)
-
-
-
(4)
-
107
4
-
-
-
(5)
-
106
5
-
-
-
(5)
-
106
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
321
(29)
-
-
18
(32)
-
278
29
-
-
71
(24)
(130)
224
(25)
-
-
69
(25)
(21)
222
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
435
(32)
-
-
18
(36)
-
385
33
-
-
71
(29)
(130)
330
(20)
-
-
69
(30)
(21)
328
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
45
9
-
-
2
(8)
-
48
-
-
-
-
(3)
(44)
1
-
-
-
-
-
-
1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
20
2
-
-
-
(3)
-
19
2
-
-
-
(3)
-
18
1
-
-
1
(3)
-
17
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
114
107
106
106
321
278
224
222
435
385
330
328
45
48
1
1
20
19
18
17
157
8
-
-
-
-
(3)
-
5
1
-
-
1
(2)
-
5
(1)
-
-
-
(1)
-
3
50
-
-
-
-
(3)
-
47
-
-
-
-
(2)
-
45
-
-
-
-
(3)
-
42
58
52
50
45
Total
508
(21)
-
-
20
(50)
-
457
36
-
-
72
(37)
(174)
354
(20)
-
-
70
(34)
(21)
349
50
-
-
-
-
(3)
-
47
-
-
-
-
(2)
-
45
-
-
-
-
(3)
-
42
558
504
399
391
Years Ended
December 31
Developed
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Undeveloped
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Natural Gas Liquids
Millions of Barrels
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Total
114
107
106
106
-
-
-
-
-
-
-
-
-
-
-
-
235
209
101
97
-
-
-
-
86
69
123
125
-
-
-
-
349
316
207
203
-
-
-
-
86
69
123
125
-
-
-
-
45
47
1
-
-
-
-
-
-
1
-
1
-
-
-
-
16
15
16
15
-
-
-
-
4
4
2
2
-
-
-
-
8
5
2
3
50
47
45
42
-
-
3
-
-
-
-
-
418
383
226
221
50
47
45
42
90
74
128
128
-
-
-
-
Notable changes in proved natural gas liquids reserves in the three years ended December 31, 2018, included:
(cid:120) Revisions: 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.
(cid:120) Extensions and discoveries: 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.
(cid:120) Sales: 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.
158
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Total company
End of 2015
End of 2016
End of 2017
End of 2018
Natural Gas
Billions of Cubic Feet
Lower Total
Asia Pacific/
Alaska
48
U.S. Canada Europe Middle East Africa
Total
2,347
(105)
-
-
2
(73)
(69)
2,102
287
-
-
2
(71)
-
2,320
150
-
335
2
(71)
-
2,736
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
5,171
(124)
-
-
162
(494)
(1)
4,714
460
-
-
582
(338)
(2,885)
2,533
(283)
-
1
527
(237)
(223)
2,318
7,518
(229)
-
-
164
(567)
(70)
6,816
747
-
-
584
(409)
(2,885)
4,853
(133)
-
336
529
(308)
(223)
5,054
1,107
111
-
1
43
(192)
(33)
1,037
8
-
-
3
(71)
(966)
11
9
-
-
11
(5)
-
26
1,359
56
-
-
-
(177)
-
1,238
167
-
-
-
(188)
-
1,217
86
-
-
110
(188)
(13)
1,212
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,347
2,102
2,320
2,736
5,171
4,714
2,533
2,318
7,518
6,816
4,853
5,054
1,107
1,037
11
26
1,359
1,238
1,217
1,212
159
1,713
18
1
-
124
(288)
(42)
1,526
16
-
-
23
(267)
-
1,298
4
-
-
23
(246)
-
1,079
5,269
(676)
-
-
125
(337)
-
4,381
111
-
-
185
(374)
-
4,303
280
-
-
362
(381)
-
4,564
6,982
5,907
5,601
5,643
227
-
-
-
-
-
-
227
-
-
-
-
(3)
-
224
-
-
-
-
(10)
-
214
11,924
(44)
1
1
331
(1,224)
(145)
10,844
938
-
-
610
(938)
(3,851)
7,603
(34)
-
336
673
(757)
(236)
7,585
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
5,269
(676)
-
-
125
(337)
-
4,381
111
-
-
185
(374)
-
4,303
280
-
-
362
(381)
-
4,564
227
227
224
214
17,193
15,225
11,906
12,149
Years Ended
December 31
Developed
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Undeveloped
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Natural Gas
Billions of Cubic Feet
Lower Total
Asia Pacific/
Alaska
48
U.S. Canada Europe Middle East Africa
Total
2,313
2,094
2,310
2,720
4,458
4,199
1,597
1,427
6,771
6,293
3,907
4,147
1,101
1,031
11
17
1,088
998
997
1,052
-
-
-
-
34
8
10
16
-
-
-
-
-
-
-
-
713
515
936
891
-
-
-
-
-
-
-
-
747
523
946
907
-
-
-
-
-
-
-
-
6
6
-
9
-
-
-
-
-
-
-
-
271
240
220
160
-
-
-
-
1,421
1,188
945
758
4,482
4,110
4,044
4,059
292
338
353
321
787
271
259
505
227
227
224
214
10,608
9,737
6,084
6,188
-
-
-
-
-
-
-
-
-
-
-
-
4,482
4,110
4,044
4,059
1,316
1,107
1,519
1,397
787
271
259
505
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.
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, 2018, included:
(cid:120) Revisions: 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. In 2016, revisions in our equity affiliates in Asia Pacific/Middle East were primarily
due to lower prices.
(cid:120) Purchases: In 2018, Alaska purchases were due to the Kuparuk Assets and Western North Slope acquisitions.
(cid:120) Extensions and discoveries: 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 Delaware, Eagle Ford and Bakken.
(cid:120) Sales: In 2018, Lower 48 sales were primarily due to the disposition of our interest in Barnett. In 2017, Lower 48 sales
were due to the disposition of our interests in the San Juan Basin and Panhandle assets, while Canada sales were due to
the disposition of a majority of our western Canada assets.
160
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Total company
End of 2015
End of 2016
End of 2017
End of 2018
161
Bitumen
Millions of Barrels
Canada
687
(515)
-
-
-
(13)
-
159
16
-
-
96
(21)
-
250
10
-
-
-
(24)
-
236
1,706
(573)
-
-
10
(54)
-
1,089
-
-
-
-
(23)
(1,066)
-
-
-
-
-
-
-
-
2,393
1,248
250
236
Years Ended
December 31
Developed
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Undeveloped
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Bitumen
Millions of Barrels
Canada
111
159
154
155
311
322
-
-
576
-
96
81
1,395
767
-
-
Notable changes in proved bitumen reserves in the three years ended December 31, 2018, included:
(cid:120) Revisions: In 2018, revisions were primarily due to higher prices at Surmont. In 2017, revisions were
primarily due to higher prices at Surmont. In 2016, for both our consolidated operations and equity
affiliates revisions were primarily related to lower prices which resulted in reserve reductions at
Surmont, Foster Creek, Christina Lake and Narrows Lake.
(cid:120) Extensions and discoveries: 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.
(cid:120) Sales: In 2017, sales were due to the disposition of our 50 percent interest in the FCCL Partnership in
Canada.
162
Years Ended
December 31
Developed and Undeveloped
Consolidated operations
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Equity affiliates
End of 2015
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
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
Total company
End of 2015
End of 2016
End of 2017
End of 2018
Total Proved Reserves
Millions of Barrels of Oil Equivalent
Lower Total
48 U.S.
Alaska
Canada
Europe
Asia Pacific/
Middle East
Africa
Total
1,420
1,771
(143)
3
-
124
(185)
-
1,570
170
-
-
378
(144)
(621)
1,353
(161)
-
1
335
(146)
(70)
(77)
6
-
33
(76)
(12)
1,294
166
6
-
41
(77)
-
1,430
102
2
289
48
(76)
-
1,795
1,312
3,191
(220)
9
-
157
(261)
(12)
2,864
336
6
-
419
(221)
(621)
2,783
(59)
2
290
383
(222)
(70)
3,107
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
930
(484)
-
-
9
(55)
(7)
393
18
-
-
97
(37)
(217)
254
12
-
-
4
(25)
-
245
1,706
(573)
-
-
10
(54)
-
1,089
-
-
-
-
(23)
(1,066)
-
-
-
-
-
-
-
-
593
11
-
-
-
(76)
-
528
68
-
-
-
(79)
-
517
40
-
-
21
(75)
(38)
465
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,420
1,294
1,430
1,795
1,771
1,570
1,353
1,312
3,191
2,864
2,783
3,107
2,636
1,482
254
245
593
528
517
465
163
497
9
7
-
28
(87)
(10)
444
36
-
-
7
(81)
-
406
5
-
-
6
(75)
-
342
1,021
(113)
-
-
21
(64)
-
865
18
-
-
31
(69)
-
845
46
-
-
60
(71)
-
880
1,518
1,309
1,251
1,222
242
-
-
-
-
(1)
-
241
-
-
-
-
(8)
-
233
6
-
-
-
(15)
-
224
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
242
241
233
224
5,453
(684)
16
-
194
(480)
(29)
4,470
458
6
-
523
(426)
(838)
4,193
4
2
290
414
(412)
(108)
4,383
2,727
(686)
-
-
31
(118)
-
1,954
18
-
-
31
(92)
(1,066)
845
46
-
-
60
(71)
-
880
8,180
6,424
5,038
5,263
Years Ended
December 31
Developed
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Undeveloped
Consolidated operations
End of 2015
End of 2016
End of 2017
End of 2018
Equity affiliates
End of 2015
End of 2016
End of 2017
End of 2018
Total Proved Reserves
Millions of Barrels of Oil Equivalent
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East
Africa
Total
1,318
1,203
1,319
1,617
1,261
1,165
682
681
2,579
2,368
2,001
2,298
-
-
-
-
-
-
-
-
102
91
111
178
510
405
671
631
-
-
-
-
-
-
-
-
-
-
-
-
612
496
782
809
-
-
-
-
352
391
158
160
311
322
-
-
578
2
96
85
1,395
767
-
-
398
365
372
382
-
-
-
-
195
163
145
83
-
-
-
-
384
309
281
244
890
820
802
796
113
135
125
98
131
45
43
84
242
241
233
221
-
-
-
-
-
-
-
3
-
-
-
-
3,955
3,674
3,045
3,305
1,201
1,142
802
796
1,498
796
1,148
1,078
1,526
812
43
84
Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six thousand cubic feet of natural gas
converts to one BOE.
Proved Undeveloped Reserves
We had 1,162 million BOE of proved undeveloped reserves at year-end 2018, compared with 1,191 million BOE at year-end
2017. The following table shows changes in total proved undeveloped reserves for 2018:
(cid:3)
End of 2017
Transfers to proved developed
Revisions
Improved recovery
Purchases
Extensions and discoveries
Sales
End of 2018
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
1,191
(270)
(208)
2
43
445
(41)
1,162
Downward revisions were primarily in our Lower 48 segment and were mainly due to changes in development timing for
specific well locations from the unconventional plays. These revisions were partially offset by higher prices in Lower 48 as well
as Alaska, Europe and APME.
164
Extensions and discoveries were primarily in Lower 48 and were mainly due to changes in the development strategy to add
specific well locations from the unconventional plays.
Purchases were due to the Kuparuk Assets and Western North Slope acquisitions in Alaska. Sales were primarily due to the
disposition of a subsidiary that held a 16.5 percent interest in the Clair Field in the United Kingdom.
At December 31, 2018, our proved undeveloped reserves represented 22 percent of total proved reserves, compared with
24 percent at December 31, 2017. Costs incurred for the year ended December 31, 2018, relating to the development of proved
undeveloped reserves were $4.6 billion. A portion of our costs incurred each year relates to development projects where the
proved undeveloped reserves will be converted to proved developed reserves in future years.
At the end of 2018, approximately 90 percent of total proved undeveloped reserves are currently 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 Europe and Asia Pacific/Middle East regions. All major development areas are currently producing and are
expected to have proved undeveloped reserves convert to proved developed over time. Approximately 77 percent of our total
proved undeveloped reserves at year-end 2018 are in North America, and all these reserve volumes are planned for development
within five years of initial disclosure.
Results of Operations
(cid:55)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)(cid:73)(cid:85)(cid:82)(cid:80)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:68)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:86)(cid:3)2018, 2017 and 2016 are shown in the following
tables. Non-oil and gas activities, such as pipeline and marine operations, liquefied natural gas (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:
(cid:120) Sales (cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72)(cid:3)(cid:86)(cid:68)(cid:79)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:88)(cid:81)(cid:68)(cid:73)(cid:73)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:72)(cid:81)(cid:87)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:87)(cid:87)(cid:85)(cid:76)(cid:69)(cid:88)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:83)(cid:85)(cid:76)(cid:80)(cid:68)(cid:85)(cid:76)(cid:79)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:182)(cid:86)(cid:3)(cid:81)(cid:72)(cid:87)(cid:3)(cid:90)(cid:82)(cid:85)(cid:78)(cid:76)(cid:81)(cid:74)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:72)(cid:86)(cid:87)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:82)(cid:92)(cid:68)(cid:79)(cid:87)(cid:92)(cid:3)
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.
(cid:120) Transportation costs reflect fees to transport our produced hydrocarbons beyond the production function to a final
delivery point using transportation operations which are consolidated.
(cid:120) Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of
hydrocarbons, and other miscellaneous income.
(cid:120) Production costs include costs incurred to operate and maintain wells, related equipment and facilities used in the
production of petroleum liquids and natural gas.
(cid:120) Taxes other than income taxes include production, property and other non-income taxes.
(cid:120) Depreciation of support equipment is reclassified as applicable.
(cid:120) Other related expenses include inventory fluctuations, foreign currency transaction gains and losses and other
miscellaneous expenses.
165
Results of Operations
Year Ended
December 31, 2018
(cid:3) Total revenues
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
(cid:3)
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
Lower Total
Alaska
48 U.S.
Other
Asia Pacific/
Canada Europe Middle East Africa Areas
Total
Millions of Dollars
$
$
$
$
4,816
5
(722)
335
4,434
964
357
59
6,573
-
-
213
6,786
1,533
432
176
11,389
5
(722)
548
11,220
2,497
789
235
582
-
-
164
746
417
21
21
4,449
-
-
737
5,186
856
33
57
3,177
545
(45)
6
3,683
646
95
43
950
-
-
110
1,060
62
3
(4)
-
-
-
432
432
2
-
20
20,547
550
(767)
1,997
22,327
4,480
941
372
-
-
(1)
-
411
(8)
5,497
10
54
331
10,642
3,726
6,916
419
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
758
2,018
-
(6)
2,770
321
804
-
640
-
(4)
15
994
103
891
616
1
16
56
2,365
419
1,946
2,279
64
63
51
2,188
466
1,722
2,895
65
79
107
4,553
885
3,668
313
9
56
7
(98)
(114)
16
1,070
(78)
(62)
178
3,132
1,354
1,778
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,186
14
(19)
39
1,679
683
996
758
2,018
-
(6)
2,770
321
804
-
640
-
(4)
15
994
103
891
33
-
1
-
965
926
39
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
166
Year Ended
December 31, 2017
(cid:3) Total revenues
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
(cid:3)
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
Lower Total
Alaska
48 U.S.
Other
Asia Pacific/
Canada Europe Middle East Africa Areas
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
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
487
-
-
48
535
44
2
61
16
-
6
-
406
428
(22)
-
-
-
-
-
-
-
-
-
-
-
322
322
(1)
-
45
-
-
-
-
278
11
267
-
-
-
-
-
-
-
-
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)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
150
-
4
2
195
26
169
-
-
-
-
-
-
-
617
1,717
22
11
(3,072)
(998)
(2,074)
-
-
-
-
-
-
-
-
-
19
-
(19)
13
(32)
Income tax provision (benefit)
Results of operations
Production costs excluding taxes have been revised to exclude the non-service components of pension related net periodic costs to conform to the current year's
presentation.
$
167
Year Ended
December 31, 2016
(cid:3) Total revenues
Consolidated operations
Sales
Transfers
Transportation costs
Other revenues
(cid:3)
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
Lower
Alaska
48
Total
U.S.
Other
Canada Europe Middle East Africa Areas
Asia Pacific/
Millions of Dollars
$ 2,793
8
(676)
375
2,500
996
231
45
$
$
738
1
52
52
385
(7)
392
-
-
-
-
-
-
-
-
4,117
-
-
111
4,228
1,852
308
1,227
4,167
148
70
72
(3,616)
(1,307)
(2,309)
6,910
8
(676)
486
6,728
2,848
539
1,272
4,905
149
122
124
(3,231)
(1,314)
(1,917)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
661
-
-
48
709
781
55
332
881
88
(51)
32
(1,409)
(406)
(1,003)
860
-
-
-
860
431
15
6
2,678
-
-
(34)
2,644
786
31
90
1,390
(161)
(77)
210
375
3
372
-
-
-
-
-
-
-
-
2,350
347
(40)
(25)
2,632
626
30
38
1,402
44
(13)
35
470
250
220
449
825
-
(2)
1,272
256
476
-
-
-
-
147
147
23
1
138
2
-
4
-
(21)
(72)
51
-
-
-
-
-
-
-
-
-
-
-
9
9
(2)
-
41
-
-
4
-
(34)
(13)
(21)
-
-
-
-
-
-
-
-
Total
12,599
355
(716)
631
12,869
5,062
656
1,911
8,580
120
(11)
401
(3,850)
(1,552)
(2,298)
1,309
825
-
(2)
2,132
687
491
6
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
309
9
(7)
8
89
24
65
-
-
-
-
-
-
-
548
-
8
7
(23)
(201)
178
-
-
-
-
-
-
-
-
-
24
-
(24)
-
(24)
857
9
25
15
42
(177)
219
Income tax provision (benefit)
Results of operations
Production costs excluding taxes have been revised to exclude the non-service components of pension related net periodic costs to conform to the current year's
presentation.
$
168
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
Other areas
Total equity affiliates
Total company
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
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
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
2018
Thousands of Barrels Daily
2017
2016
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
171
229
400
1
113
89
36
639
14
-
14
653
14
69
83
1
8
3
95
7
102
66
-
66
167
180
347
3
122
93
20
585
14
-
14
599
14
69
83
9
8
4
104
7
111
59
63
122
163
195
358
7
120
97
2
584
14
-
14
598
12
88
100
23
7
7
137
8
145
35
148
183
Millions of Cubic Feet Daily
6
596
602
12
475
626
28
1,743
1,031
2,774
7
898
905
187
476
687
8
2,263
1,007
3,270
25
1,219
1,244
524
459
730
1
2,958
899
3,857
169
Average Sales Prices
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 equity affiliates
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(cid:178)Asia Pacific/Middle East
Total operations
Bitumen Per Barrel
Consolidated operations—Canada
Equity affiliates—Canada
2018
2017
2016
$
$
$
60.23 (cid:3)
62.99 (cid:3)
61.75 (cid:3)
48.73 (cid:3)
70.98 (cid:3)
70.93 (cid:3)
69.83 (cid:3)
70.67 (cid:3)
65.01 (cid:3)
(cid:3)
72.49 (cid:3)
72.49 (cid:3)
65.17 (cid:3)
(cid:3)
(cid:3)
(cid:3)
27.30 (cid:3)
27.30 (cid:3)
43.70 (cid:3)
36.87 (cid:3)
47.20 (cid:3)
40.00 (cid:3)
29.03 (cid:3)
45.69 (cid:3)
30.48 (cid:3)
(cid:3)
(cid:3)
22.29 (cid:3)
- (cid:3)
(cid:3)
42.69
47.36
45.01
43.69
54.04
54.38
55.11
54.16
48.70
54.76
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
31.68
37.49
34.70
35.25
43.66
42.23
-
42.76
37.67
44.11
44.11
37.82
14.34
14.34
14.82
22.62
29.00
19.06
15.72
31.13
16.68
12.91
15.80
$
Natural Gas Per Thousand Cubic Feet
Consolidated operations
5.22
Alaska
2.20
Lower 48
2.24
United States
1.49
Canada
4.71
Europe
4.15
Asia Pacific/Middle East
-
Africa
3.49
Total international
2.97
Total consolidated operations
2.97
Equity affiliates(cid:178)Asia Pacific/Middle East
2.97
Total operations
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.
2.48 (cid:3)
2.82 (cid:3)
2.82 (cid:3)
1.00 (cid:3)
7.79 (cid:3)
5.95 (cid:3)
4.84 (cid:3)
6.64 (cid:3)
5.33 (cid:3)
6.06 (cid:3)
5.60 (cid:3)
2.72
2.73
2.73
1.93
5.72
4.66
3.53
4.64
3.87
4.27
4.00
170
2018
2017
2016
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
Other areas
Total equity affiliates
Average Production Costs Per Barrel(cid:178)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
Other areas
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
Other areas
Total equity affiliates
*Includes bitumen.
$
$
$
$
14.20
10.58
11.73
16.32
11.73
9.03
4.14
10.72
11.26
-
4.56
-
4.56
13.59
-
5.26
2.98
3.71
0.82
0.45
1.33
0.20
0.82
2.37
-
11.41
-
11.41
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
15.20
10.41
11.70
14.04
10.58
7.57
31.42
10.38
11.08
7.96
4.04
-
5.85
24.59
7.96
3.53
1.73
2.21
0.99
0.42
0.36
1.37
0.55
1.44
0.28
7.52
-
4.18
11.26
23.43
20.15
15.84
18.71
16.95
2.73
17.22
18.78
5.70
8.65
-
7.29
171
Development and Exploration Activities
The following two tables summarize our net interest in productive and dry exploratory and development wells
in the years ended December 31, 2018, 2017 and 2016(cid:17)(cid:3)(cid:3)(cid:36)(cid:3)(cid:179)(cid:71)(cid:72)(cid:89)(cid:72)(cid:79)(cid:82)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:180)(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:71)(cid:85)(cid:76)(cid:79)(cid:79)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)
(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71)(cid:3)(cid:68)(cid:85)(cid:72)(cid:68)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:82)(cid:76)(cid:85)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:71)(cid:72)(cid:83)(cid:87)(cid:75)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:76)(cid:74)(cid:85)(cid:68)(cid:83)(cid:75)(cid:76)(cid:70)(cid:3)(cid:75)(cid:82)(cid:85)(cid:76)(cid:93)(cid:82)(cid:81)(cid:3)(cid:78)(cid:81)(cid:82)(cid:90)(cid:81)(cid:3)(cid:87)(cid:82)(cid:3)(cid:69)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:17)(cid:3)(cid:3)(cid:36)(cid:81)(cid:3)(cid:179)(cid:72)(cid:91)(cid:83)(cid:79)(cid:82)(cid:85)(cid:68)(cid:87)(cid:82)(cid:85)(cid:92)(cid:3)
(cid:90)(cid:72)(cid:79)(cid:79)(cid:180)(cid:3)(cid:76)(cid:86)(cid:3)(cid:68)(cid:3)(cid:90)(cid:72)(cid:79)(cid:79)(cid:3)(cid:71)(cid:85)(cid:76)(cid:79)(cid:79)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:73)(cid:76)(cid:81)(cid:71)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:72)(cid:3)(cid:70)(cid:85)(cid:88)(cid:71)(cid:72)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:82)(cid:85)(cid:3)(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:68)(cid:81)(cid:3)(cid:88)(cid:81)(cid:78)(cid:81)(cid:82)(cid:90)(cid:81)(cid:3)(cid:73)(cid:76)(cid:72)(cid:79)(cid:71)(cid:3)(cid:82)(cid:85)(cid:3)(cid:68)(cid:3)(cid:81)ew 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 coalbed methane test wells located in Asia Pacific/Middle
East.
Net Wells Completed
Productive
2017
2018
2016
2018
2017
2016
Dry
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
(cid:3)
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.
(cid:3)
(cid:3)
-
1
1
-
*
-
*
-
1
-
-
(cid:3) (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
- (cid:3)
-
3
3
-
*
1
-
1
5
-
-
(cid:3)
-
-
-
-
-
-
-
-
-
-
-
-
-
(cid:3)
1
1
2
1
1
-
-
-
4
-
-
-
-
-
2
-
-
-
-
2
-
-
-
-
6 (cid:3)
45 (cid:3)
51 (cid:3)
2 (cid:3)
* (cid:3)
2 (cid:3)
- (cid:3)
- (cid:3)
55 (cid:3)
(cid:3)
6 (cid:3)
6 (cid:3)
(cid:3)
11 (cid:3)
254 (cid:3)
265 (cid:3)
1 (cid:3)
9 (cid:3)
12 (cid:3)
1 (cid:3)
- (cid:3)
288 (cid:3)
- (cid:3)
75 (cid:3)
- (cid:3)
75 (cid:3)
-
13
13
13
*
1
-
-
27
14
14
(cid:3)
(cid:3)
9
161
170
13
7
8
-
-
198
19
84
-
103
2
8
10
8
*
1
1
- (cid:3)
(cid:3)
20
20
20
(cid:3)
9
119
128
47
7
6
-
-
188
48
108
-
156
172
The table below represents the status of our wells drilling at December 31, 2018, 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, 2018.
(cid:3)
Wells at December 31, 2018
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
In Progress
Gross
Net
(cid:3)
(cid:3)
Oil
(cid:3)
(cid:3)
Productive*
(cid:3)
(cid:3)
Gas
Gross
Net
Gross
Net
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated operations
Equity affiliates
328
Asia Pacific/Middle East
Total equity affiliates
328
*Includes 18 gross and 6 net multiple completion wells.
5
330
335
15
15
9
8
382
5
177
182
14
2
4
1
203
79
79
1,692
9,749
11,441
183
497
386
830
13,337
-
-
1,012
4,507
5,519
92
86
161
135
5,993
-
-
-
4,339
4,339
33
155
58
9
4,594
3,950
3,950
-
1,647
1,647
29
52
29
2
1,759
987
987
Acreage at December 31, 2018
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
675
2,429
3,104
200
787
1,597
358
-
6,046
464
1,962
2,426
119
231
742
58
-
3,576
1,408
10,322
11,730
3,267
2,730
12,065
12,545
560
42,897
1,255
8,378
9,633
1,793
807
6,806
2,049
323
21,411
(cid:3)
(cid:3)
947
947
219
219
4,198
4,198
969
969
173
Alaska
Lower
48
Total
U.S.
Canada
Europe
Asia Pacific/
Middle East * Africa
Other
Areas
Total
Millions of Dollars
Costs Incurred
Year Ended
December 31
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
2016
Consolidated operations
Unproved property acquisition
Proved property acquisition
Exploration
Development
$
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
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
110
720
830
127
5
132
656
782
1,570
127
5
132
766
1,502
2,400
-
-
-
-
-
-
76
-
76
56
102
234
-
-
-
6
150
156
59
19
78
286
209
573
-
-
-
-
-
-
-
-
-
52
784
836
-
-
-
-
-
-
-
-
-
65
62
127
-
-
-
82
773
855
-
-
-
22
206
228
15
-
15
139
388
542
-
-
-
38
403
441
-
-
-
52
387
439
-
-
-
(6)
16
10
-
-
-
-
-
-
-
-
-
61
10
71
-
-
-
-
-
-
-
-
-
215
6
221
Equity affiliates
Unproved property acquisition
Proved property acquisition
$
-
-
-
-
-
-
*Certain amounts in Asia Pacific/Middle East equity affiliates have been revised in 2016 to reflect additional abandonment obligations.
2
-
2
19
320
341
-
-
-
15
367
382
Exploration
Development
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
$
-
-
-
-
-
-
174
-
-
-
41
-
41
371
2,249
2,620
975
5,226
8,821
-
-
-
-
-
-
-
-
-
42
-
42
-
-
-
-
-
-
-
-
-
67
-
67
-
-
-
-
-
-
-
-
-
22
206
228
376
35
411
823
3,579
4,813
-
-
-
44
553
597
186
24
210
1,451
2,166
3,827
2
-
2
34
687
723
Capitalized Costs
At December 31
2018
Consolidated operations
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
Equity affiliates
Proved property
Unproved property
Accumulated depreciation,
depletion and amortization
2017
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
$ 20,154
1,184
21,338
35,269 55,423
2,309
36,394 57,732
1,125
5,946 23,520
188
1,083
7,029 23,708
14,866
874
15,740
902
119
1,021
- 100,657
4,662
89
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
$ 18,149
1,068
19,217
35,332 53,481
2,205
36,469 55,686
1,137
6,217 27,221
290
7,202 27,511
985
14,236
822
15,058
889
122
1,011
- 102,044
67
4,491
67 106,535
9,497
$ 9,720
24,211 33,708
12,258 21,978
1,582 18,068
9,443
5,620
8,916
6,142
312
699
9
58
62,595
43,940
$
$
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9,750
2,215
11,965
5,342
6,623
-
-
-
-
-
-
-
-
-
-
9,750
2,215
11,965
5,342
6,623
175
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for
existing contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescribed 10 percent discount factor.
Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic
conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data
becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The
calculations also require assumptions as to the timing of future production of proved reserves and the timing and amount of
future development costs, including dismantlement, and future production costs, including taxes other than income taxes.
While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a
fair estimate of the present value of cash flows to be obtained from their development and production.
Discounted Future Net Cash Flows
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
Lower
Alaska
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
42,755
10,053
5,538
23,726
10,349
$ 13,377
21,363
12,136
4,418
19,005
6,461
12,544
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
-
33,606
16,449
1,228
3,147
12,782
4,853
7,929
-
-
-
-
-
-
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
176
2017
Consolidated operations
Future cash inflows
Less:
Future production costs
Future development costs
Future income tax provisions (benefit)
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
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
177
2016
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
Lower
Alaska
48
Total
U.S. Canada Europe Middle East Africa
Asia Pacific/
Total
Millions of Dollars
$ 29,697 31,963
61,660
4,739
18,533
12,770
10,715
108,417
$
$
$
$
24,965 16,936
8,932
744
5,351
976
4,375
7,961
-
(3,229)
(3,143)
(86)
5,103
1,586
-
41,901
16,893
744
2,122
(2,167) (1,297)
4,289
(1,950) 1,440
(2)
(653) 1,442
7,469
9,949
(325)
5,288
2,777
1,563
3,142
572
2,570
1,420
537
7,885
873
370
503
61,181
31,742
9,867
5,627
(2,524)
8,151
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
15,139
-
-
-
-
-
-
8,514
4,993
164
1,468
540
928
-
-
-
-
-
-
-
17,829
-
32,968
10,620
980
1,309
4,920
1,911
3,009
-
-
-
-
-
-
19,134
5,973
1,473
6,388
2,451
3,937
(86)
4,375
4,289
275
1,442
5,579
503
12,088
178
Sources of Change in Discounted Future Net Cash Flows
Consolidated Operations
2018
2017
2016
Millions of Dollars
Equity Affiliates
Total Company
2018
2017
2016
2018
2017
2016
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
$
20,609
8,151
16,562
4,395
3,937
9,027
25,004
12,088
25,589
(14,909)
(9,844)
(6,313)
(1,651)
(1,341)
(956)
(16,560)
(11,185)
(7,269)
25,391
19,310
(16,476)
4,559
2,750
(9,317)
29,950
22,060
(25,793)
4,574
5,197
1,445
3,653
1,358
3,118
382
271
(4)
426
(77)
722
4,956
5,468
1,441
4,079
1,281
3,840
(1,141)
1,225
6,646
14
(64)
2,435
(1,127)
1,161
9,081
3,033
-
2
(1,531)
(855)
(123)
-
-
(365)
3,055
(8,479)
14,825
2,300
1,313
(6,089)
12,458
(3,252)
2,540
4,089
(8,411)
62
485
(588)
3,534
-
-
3,033
-
2
(786)
(648)
413
(288)
458
-
(1,531)
(1,641)
(123)
(436)
1,058
1,481
(5,090)
(303)
3,540
(9,067)
18,359
1,652
1,726
(6,377)
12,916
(3,688)
3,598
5,570
(13,501)
35,434
20,609
8,151
7,929
4,395
3,937
43,363
25,004
12,088
(cid:120) 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.
(cid:120) 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.
(cid:120) 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.
(cid:120) (cid:55)(cid:75)(cid:72)(cid:3)(cid:68)(cid:70)(cid:70)(cid:85)(cid:72)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:3)(cid:76)(cid:86)(cid:3)(cid:20)(cid:19)(cid:3)(cid:83)(cid:72)(cid:85)(cid:70)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:83)(cid:85)(cid:76)(cid:82)(cid:85)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:182)(cid:86)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:73)(cid:88)(cid:87)(cid:88)(cid:85)(cid:72)(cid:3)(cid:70)(cid:68)(cid:86)(cid:75)(cid:3)(cid:76)(cid:81)(cid:73)(cid:79)(cid:82)(cid:90)(cid:86)(cid:15)(cid:3)(cid:79)(cid:72)(cid:86)(cid:86)(cid:3)(cid:73)(cid:88)(cid:87)(cid:88)(cid:85)(cid:72)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
development costs.
(cid:120) The net change in income taxes is the annual change in the discounted future income tax provisions.
179
Selected Quarterly Financial Data (Unaudited)
Sales and
Other
Operating
Revenues
$
8,798
8,504
9,449
9,666
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
1,776
2,619
2,906
2,672
900
1,654
1,873
1,878
888
1,640
1,861
1,868
0.75
1.40
1.60
1.62
0.75
1.39
1.59
1.61
2018
First
Second
Third
Fourth
$
2017
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.
599
(3,426)
436
1,598
586
(3,440)
420
1,579
(232)
(4,361)
653
1,325
7,518
6,781
6,688
8,119
0.47
(2.78)
0.35
1.32
0.47
(2.78)
0.34
1.32
180
Supplementary Information(cid:178)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:
(cid:120) ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC (in each case, reflecting
investments in subsidiaries utilizing the equity method of accounting).
(cid:120) All other nonguarantor subsidiaries of ConocoPhillips.
(cid:120) (cid:55)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:81)(cid:72)(cid:70)(cid:72)(cid:86)(cid:86)(cid:68)(cid:85)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)(cid:82)(cid:81)(cid:3)(cid:68)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:86)(cid:76)s.
(cid:44)(cid:81)(cid:3)(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:21)(cid:19)(cid:20)(cid:27)(cid:15)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:3)(cid:38)(cid:68)(cid:81)(cid:68)(cid:71)(cid:68)(cid:3)(cid:41)(cid:88)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:38)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:3)(cid:44)(cid:182)(cid:86)(cid:3)(cid:74)(cid:88)(cid:68)(cid:85)(cid:68)(cid:81)(cid:87)(cid:72)(cid:72)(cid:71)(cid:15)(cid:3)(cid:83)(cid:88)(cid:69)(cid:79)(cid:76)(cid:70)(cid:79)(cid:92)(cid:3)(cid:75)(cid:72)(cid:79)(cid:71)(cid:3)(cid:71)(cid:72)(cid:69)(cid:87)(cid:3)(cid:86)(cid:72)(cid:70)(cid:88)(cid:85)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)
were assumed by Burlington Resources LLC. The assumption did not significantly change the nature of the
outstanding debt or the terms of the parental guarantees, which remain full and unconditional, as well as joint
and several. The assumption did not impact our consolidated financial position, results of operations or cash
flows. Financial information for ConocoPhillips Canada Funding Company I is p(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:36)(cid:79)(cid:79)(cid:3)(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)
(cid:54)(cid:88)(cid:69)(cid:86)(cid:76)(cid:71)(cid:76)(cid:68)(cid:85)(cid:76)(cid:72)(cid:86)(cid:180)(cid:3)(cid:70)(cid:82)(cid:79)(cid:88)(cid:80)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:71)(cid:72)(cid:81)(cid:86)(cid:72)(cid:71)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:73)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:17)(cid:3)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:83)(cid:85)(cid:76)(cid:82)(cid:85)(cid:3)(cid:92)(cid:72)(cid:68)(cid:85)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:85)(cid:68)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)
periods have been restated to reflect the current period condensed consolidating financial information
presentation.
In 2016, ConocoPhillips received a $2.3 billion return of capital from ConocoPhillips Company to settle
certain accumulated intercompany balances. The transaction had no impact on our consolidated financial
statements.
In 2016, ConocoPhillips Canada Funding Company I repaid $1.25 billion of external debt. This transaction
was reflected in the full-year 2016 condensed consolidating financial statements.
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.
This condensed consolidating financial information should be read in conjunction with the accompanying
consolidated financial statements and notes.
181
$
$
$
$
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
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
$
Millions of Dollars
Year Ended December 31, 2018
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
-
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
Year Ended December 31, 2017*
-
(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)
Comprehensive Income (Loss) Attributable to ConocoPhillips
*Certain amounts have been reclassified to conform to the current-period presentation resulting from the adoption of ASU No. 2017-07. See Note 2—Changes in Accounting Principles, for additional information.
See Notes to Consolidated Financial Statements.
(4,168)
2,275
1,672
(180)
221
$
182
$
Income Statement
Revenues and Other Income
Sales and other operating revenues
Equity in earnings (losses) 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
Loss before income taxes
Income tax benefit
Net loss
Less: net income attributable to noncontrolling interests
Net Loss Attributable to ConocoPhillips
$
Millions of Dollars
Year Ended December 31, 2016*
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
-
(3,351)
-
1
88
(3,262)
-
-
8
-
-
-
-
-
506
(19)
-
495
(3,757)
(142)
(3,615)
-
(3,615)
10,352
(1,051)
120
(11)
277
9,687
9,144
754
331
1,229
1,178
67
162
46
622
2
277
13,812
(4,125)
(774)
(3,351)
-
(3,351)
-
(2,270)
-
-
21
(2,249)
-
1
-
-
-
-
-
-
37
(110)
-
(72)
(2,177)
(92)
(2,085)
-
(2,085)
13,341
61
240
265
2,995
16,902
3,562
5,130
140
683
7,884
72
577
379
501
108
-
19,036
(2,134)
(963)
(1,171)
(56)
(1,227)
-
6,663
-
-
(3,381)
3,282
(2,712)
(242)
(6)
-
-
-
-
-
(421)
-
-
(3,381)
6,663
-
6,663
-
6,663
23,693
52
360
255
-
24,360
9,994
5,643
473
1,912
9,062
139
739
425
1,245
(19)
277
29,890
(5,530)
(1,971)
(3,559)
(56)
(3,615)
(3,561)
Comprehensive Loss Attributable to ConocoPhillips
*Certain amounts have been reclassified to conform to the current-period presentation resulting from the adoption of ASU No. 2017-07. See Note 2—Changes in Accounting Principles, for additional information.
See Notes to Consolidated Financial Statements.
(1,641)
(3,561)
(3,297)
(1,149)
6,087
$
183
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
(cid:47)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)
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
(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)
Noncontrolling interests
(cid:55)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:47)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)
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
(cid:47)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)
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
(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:82)(cid:81)(cid:3)(cid:86)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)
Noncontrolling interests
(cid:55)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:47)(cid:76)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:87)(cid:82)(cid:70)(cid:78)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:182)(cid:3)(cid:40)(cid:84)(cid:88)(cid:76)(cid:87)(cid:92)
*Includes intercompany loans.
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Millions of Dollars
At December 31, 2018
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
234
-
2,214
1,899
163
277
4,787
47,974
4,230
1,146
58,137
3,094
2,505
65
554
314
6,532
9,321
432
-
1,335
5,229
22,849
13,342
21,946
-
58,137
-
-
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
At December 31, 2017
3
-
294
-
-
24
321
12,273
-
672
13,266
264
7
-
-
17
288
500
-
-
-
1,446
2,234
(753)
11,785
-
13,266
6,088
1,873
4,910
-
897
763
14,531
14,547
41,930
1,043
72,051
3,794
77
973
171
642
5,657
3,998
7,199
6,490
519
10,135
33,998
7,669
30,190
194
72,051
-
-
(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)
-
-
(3,122)
-
-
(30)
(3,152)
(94,134)
(477)
(1,769)
(99,532)
(3,122)
(9)
-
-
(29)
(3,160)
(478)
-
(1,208)
-
(17,069)
(21,915)
(13,759)
(63,858)
-
(99,532)
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
6,325
1,873
4,320
1,899
1,060
1,035
16,512
10,060
45,683
1,107
73,362
4,030
2,575
1,038
725
1,029
9,397
17,128
7,631
5,282
1,854
1,269
42,561
29,391
1,216
194
73,362
$
$
$
$
$
$
$
$
-
-
28
-
-
1
29
29,942
-
4
29,975
-
(3)
-
-
85
82
3,791
-
-
-
725
4,598
27,512
(2,135)
-
29,975
-
-
24
-
-
1
25
29,400
-
15
29,440
-
(5)
-
-
85
80
3,787
-
-
-
1,528
5,395
22,892
1,153
-
29,440
184
Statement of Cash Flows
ConocoPhillips
Company
Resources LLC
Millions of Dollars
Year Ended December 31, 2018
Burlington
ConocoPhillips
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
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(cid:178)related parties
Collection of advances/loans(cid:178)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 purchases of short-term investments
Long-term advances/loans(cid:178)related parties
Collection of advances/loans(cid:178)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
$
4,317
4,183
2,764
14,132
(12,462)
12,934
-
-
-
-
-
589
(803)
-
(214)
-
-
254
(2,999)
(1,363)
5
(4,103)
-
-
-
-
(980)
(110)
502
-
(126)
3,432
3,504
151
6,373
10
(4,865)
-
-
(1,043)
(3,468)
(9,366)
4
1,194
234
1,428
(603)
-
-
-
(173)
212
(2,150)
-
(2,714)
-
(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
-
(125)
-
309
(4,243)
-
-
(3,449)
(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
Year Ended December 31, 2017
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
(4,351)
-
12,178
-
(65)
389
(1,341)
-
6,810
-
-
-
-
-
(9,781)
(9,781)
(2)
(2)
5
(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 and Cash Equivalents at End of Period
*Restated to include $211 million of restricted cash at January 1, 2018. See Note 2(cid:886)Changes in Accounting Principles for additional information relating to the adoption of ASU No. 2016-18.
Restricted cash totaling $236 million is included in the "Other assets" line of our Consolidated Balance Sheet as of December 31, 2018.
234
3
-
$
185
Statement of Cash Flows
ConocoPhillips
Company
ConocoPhillips
Millions of Dollars
Year Ended December 31, 2016
All Other
Subsidiaries
Resources LLC
Burlington
Consolidating
Adjustments
Total
Consolidated
$
(306)
(322)
799
5,902
(1,670)
4,403
-
-
2,300
-
-
-
(2,214)
-
86
1,600
(150)
148
(126)
(1,253)
1
220
-
-
-
-
(989)
(126)
266
-
(812)
391
1,433
1
164
2,994
(164)
-
-
-
(2,315)
515
(3)
354
4
358
(1,714)
-
-
-
-
-
912
-
(802)
-
-
-
-
-
-
-
2
(1)
6
5
(4,281)
(205)
1,114
(51)
-
272
(131)
(3)
(3,285)
812
(2,492)
-
-
(1,881)
1,898
(1,663)
(65)
889
2,358
3,247
2,115
-
(2,394)
-
812
(555)
-
-
(22)
(812)
555
(211)
-
1,881
279
1,692
-
-
-
-
(4,869)
(331)
1,286
(51)
-
108
-
(2)
(3,859)
4,594
(2,251)
(63)
(126)
(1,253)
(137)
764
(66)
1,242
2,368
3,610
Cash Flows From Operating Activities
Net Cash Provided by (Used in) 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(cid:178)related parties
Collection of advances/loans(cid:178)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 Provided by (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
$
186
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, 2018, 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
(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:71)(cid:76)(cid:86)(cid:70)(cid:79)(cid:82)(cid:86)(cid:88)(cid:85)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:85)(cid:82)(cid:70)(cid:72)(cid:71)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:11)(cid:68)(cid:86)(cid:3)(cid:71)(cid:72)(cid:73)(cid:76)(cid:81)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:53)(cid:88)(cid:79)(cid:72)(cid:3)(cid:20)(cid:22)(cid:68)-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, 2018.
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.
M(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:182)(cid:86)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:44)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:79)(cid:3)(cid:38)(cid:82)(cid:81)(cid:87)(cid:85)(cid:82)(cid:79)(cid:3)(cid:50)(cid:89)(cid:72)(cid:85)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)
This report is included in Item 8 on page 82 and is incorporated herein by reference.
Report of Independent Registered Public Accounting Firm
This report is included in Item 8 on page 84 and is incorporated herein by reference.
Item 9B. OTHER INFORMATION
None.
187
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report on pages 29 and 30.
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
(cid:86)(cid:76)(cid:80)(cid:76)(cid:79)(cid:68)(cid:85)(cid:3)(cid:73)(cid:88)(cid:81)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:17)(cid:3)(cid:3)(cid:58)(cid:72)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:83)(cid:82)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:68)(cid:3)(cid:70)(cid:82)(cid:83)(cid:92)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:38)(cid:82)(cid:71)(cid:72)(cid:3)(cid:82)(cid:73)(cid:3)(cid:40)(cid:87)(cid:75)(cid:76)(cid:70)(cid:86)(cid:3)(cid:82)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:179)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:42)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
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
(cid:179)(cid:38)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:42)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:180)(cid:3)(cid:86)(cid:72)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:76)(cid:81)(cid:87)(cid:72)(cid:85)(cid:81)(cid:72)(cid:87)(cid:3)(cid:90)(cid:72)(cid:69)(cid:86)(cid:76)(cid:87)(cid:72)(cid:17)
All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our
2019 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2019, 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 2019
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2019, 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 2019
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2019, 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 2019
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2019, 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 2019
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2019, 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 2019 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.
188
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 81, are filed as part of this annual report.
2. Financial Statement Schedules
Schedule II(cid:178)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 190 through 199, are filed as part
of this annual report.
SCHEDULE II(cid:178)VALUATION AND QUALIFYING ACCOUNTS (Consolidated)
(cid:3)
ConocoPhillips
(cid:3) (cid:3)
(cid:3)
(cid:3) (cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Millions of Dollars
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
Other (a) Deductions
Balance at
December 31
53
-
(8) (cid:3)
January 1
4
1,254
23
2,067
Balance at Charged to
Expense
(cid:3)
Description
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
2016
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable $
Deferred tax asset valuation allowance
Included in other liabilities:
(cid:3) 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.
5
675
2
560
7
734
3
(31)
(1)
(12)
-
19
129
156
65
70
80
(2)
1
(2) (b)
(273)
(73) (c)
(3) (b)
-
(93) (c)
(4) (b)
(16)
(206) (c)
25
3,040
48
4
1,254
53
5
675
80
189
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.
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).
Exhibit
Number
2.1
(cid:21)(cid:17)(cid:21)(cid:130)(cid:193)
(cid:21)(cid:17)(cid:22)(cid:130)(cid:193)
3.1
3.2
3.3
10.1
10.2
190
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 Amendment and Restatement of ConocoPhillips Key Employee Supplemental Retirement Plan,
dated April 19, 2012 (incorporated by reference to Exhibit 10.13 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.10.2 First Amendment to the ConocoPhillips Key Employee Supplemental Retirement Plan, dated July
20, 2015 (incorporated by reference to Exhibit 10.10.2 to the Annual Report of ConocoPhillips on
Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.10.3 Second Amendment to the ConocoPhillips Key Employee Supplemental Retirement Plan, dated
March 14, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-32395).
10.10.4 Eighth Amendment to Retirement Plan 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 Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips(cid:178)Title I,
dated April 19, 2012 (incorporated by reference to Exhibit 10.11.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.11.2 Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips(cid:178)Title II,
dated April 19, 2012 (incorporated by reference to Exhibit 10.11.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
191
Exhibit
Number
Description
10.11.3 First Amendment to the Defined Contribution Make-Up Plan of ConocoPhillips(cid:178)Title II, dated
October 11, 2012 (incorporated by reference to Exhibit 10.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012; File No. 001-32395).
10.11.4 Second Amendment to the Defined Contribution Make-Up Plan of ConocoPhillips(cid:178)Title II, dated
December 17, 2015 (incorporated by reference to Exhibit 10.11.4 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.12
10.13
10.14
10.15
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).
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).
10.17.1 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).
10.17.2 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).
10.17.3 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).
10.17.4 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).
10.17.5 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).
10.17.6 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).
10.17.7 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).
192
Exhibit
Number
Description
10.17.8 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).
10.18.1 (cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:3)(cid:39)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:182)(cid:3)(cid:38)(cid:75)(cid:68)(cid:85)(cid:76)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:42)(cid:76)(cid:73)(cid:87)(cid:3)(cid:51)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:3)(cid:11)(cid:76)(cid:81)(cid:70)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:85)(cid:72)(cid:73)(cid:72)(cid:85)(cid:72)(cid:81)(cid:70)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)(cid:40)(cid:91)(cid:75)(cid:76)(cid:69)(cid:76)(cid:87)(cid:3)(cid:20)(cid:19)(cid:17)(cid:23)(cid:19)(cid:3)(cid:87)(cid:82)(cid:3)
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003;
File No. 000-49987).
10.18.2 (cid:41)(cid:76)(cid:85)(cid:86)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:54)(cid:72)(cid:70)(cid:82)(cid:81)(cid:71)(cid:3)(cid:36)(cid:80)(cid:72)(cid:81)(cid:71)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:3)(cid:39)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:86)(cid:182)(cid:3)(cid:38)(cid:75)(cid:68)(cid:85)(cid:76)(cid:87)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:42)(cid:76)(cid:73)(cid:87)(cid:3)(cid:51)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:3)
(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).
10.19
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).
10.20.1 Amendment and Restatement of Key Employee Deferred Compensation Plan of ConocoPhillips(cid:178)
Title I, dated April 19, 2012 (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).
10.20.2 Amendment and Restatement of Key Employee Deferred Compensation Plan of ConocoPhillips(cid:178)
Title II, dated April 19, 2012 (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).
10.20.3 First Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips(cid:178)Title II
(incorporated by reference to Exhibit 10.20.3 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2010; File No. 001-32395).
10.20.4 Second Amendment to the Key Employee Deferred Compensation Plan of ConocoPhillips(cid:178)Title II
(incorporated by reference to Exhibit 10.20.4 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2010; File No. 001-32395).
10.20.5 Amendment and Restatement of Key Employee Deferred Compensation Plan of ConocoPhillips(cid:178)
Title II, 2013 Restatement dated November 17, 2014 (Amended and Restated effective as of January
1, 2013) (incorporated by reference to Exhibit 10.20.5 to the Annual Report of ConocoPhillips on
Form 10-K for the year ended December 31, 2014; File No. 001-32395).
10.21
10.22
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).
10.23.1
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
(cid:87)(cid:82)(cid:3)(cid:36)(cid:83)(cid:83)(cid:72)(cid:81)(cid:71)(cid:76)(cid:91)(cid:3)(cid:38)(cid:3)(cid:82)(cid:73)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:51)(cid:85)(cid:82)(cid:91)(cid:92)(cid:3)(cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:54)(cid:70)(cid:75)(cid:72)(cid:71)(cid:88)(cid:79)(cid:72)(cid:3)(cid:20)(cid:23)(cid:36)(cid:3)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:21)(cid:19)(cid:19)(cid:23)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)
Meeting of Shareholders; File No. 000-49987).
193
Exhibit
Number
Description
10.23.2 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).
10.23.3 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).
10.24
10.25
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
(cid:87)(cid:82)(cid:3)(cid:36)(cid:83)(cid:83)(cid:72)(cid:81)(cid:71)(cid:76)(cid:91)(cid:3)(cid:36)(cid:3)(cid:82)(cid:73)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:51)(cid:85)(cid:82)(cid:91)(cid:92)(cid:3)(cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:54)(cid:70)(cid:75)(cid:72)(cid:71)(cid:88)(cid:79)(cid:72)(cid:3)(cid:20)(cid:23)(cid:36)(cid:3)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:21)(cid:19)(cid:19)(cid:28)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)
Meeting of Shareholders; File No. 001-32395).
10.26.1
2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix (cid:36)(cid:3)(cid:82)(cid:73)(cid:3)(cid:38)(cid:82)(cid:81)(cid:82)(cid:70)(cid:82)(cid:51)(cid:75)(cid:76)(cid:79)(cid:79)(cid:76)(cid:83)(cid:86)(cid:182)(cid:3)(cid:51)(cid:85)(cid:82)(cid:91)(cid:92)(cid:3)(cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:81)(cid:3)(cid:54)(cid:70)(cid:75)(cid:72)(cid:71)(cid:88)(cid:79)(cid:72)(cid:3)(cid:20)(cid:23)(cid:36)(cid:3)(cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:87)(cid:82)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:21)(cid:19)(cid:20)(cid:20)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)
Meeting of Shareholders; File No. 001-32395).
10.26.2 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).
10.26.5 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).
10.26.6 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).
10.26.7 Form of Performance Share Unit Agreement(cid:178)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).
10.26.8 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).
10.26.9 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).
194
Exhibit
Number
Description
10.26.10 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).
10.26.11 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).
10.26.12 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).
10.26.13 Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock Program
granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 18, 2014 (incorporated by reference to Exhibit 10.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
10.26.14 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).
10.26.15 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).
10.26.16 Form of Performance Period IX Award Agreement(cid:178)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).
10.26.17 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).
10.26.18 Form of Performance Period X Award Agreement(cid:178)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 10.6 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.26.19 Form of Performance Period XII 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 10.9 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-
32395).
195
Exhibit
Number
Description
10.26.20 Form of Performance Period XII Award Agreement(cid:178)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 10.10 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
001-32395).
10.26.21 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).
10.26.22 Form of Performance Period XIV Award Agreement(cid:178)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).
10.26.23 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).
10.26.24 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).
10.26.25 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).
10.27.1
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).
10.27.3 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).
10.27.4 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).
10.27.5 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,
196
Exhibit
Number
Description
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).
10.27.6 Form of Non-Employee Director Restricted Stock Units Terms and Conditions (cid:177) 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
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-
32395).
10.27.7 Form of Non-Employee Director Restricted Stock Units Terms and Conditions (cid:177) 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).
10.27.8 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).
10.27.9 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).
10.27.10 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).
10.27.11 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).
10.27.12 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).
10.27.13 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).
10.27.14 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).
197
Exhibit
Number
.
Description
10.27.15 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).
10.27.16* 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.
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
Amendment and Restatement of Annex to Nonqualified Deferred Compensation Arrangements of
ConocoPhillips, dated April 19, 2012 (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).
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).
198
Exhibit
Number
10.38
Description
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).
10.39* Company Retirement Contribution Make-up Plan of ConocoPhillips, dated December 28, 2018.
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* XBRL Instance Document.
101.SCH* XBRL Schema Document.
101.CAL* XBRL Calculation Linkbase Document.
101.DEF* XBRL Definition Linkbase Document.
101.LAB* XBRL Labels Linkbase Document.
101.PRE* XBRL Presentation Linkbase Document.
* Filed herewith.
(cid:130) 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.
(cid:193) 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.
199
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 19, 2019
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 19, 2019, 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)
200
/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
/s/ Harald J. Norvik
Harald J. Norvik
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
201
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LETTER TO SHAREHOLDERS
BOARD OF DIRECTORS
(As of Feb. 19, 2019)
Dear Fellow Shareholders:
The ConocoPhillips team delivered another exceptional year in 2018. Our operational
performance drove strong financial results and generated sector-leading total
shareholder returns (TSR) of 16 percent. We view this strong TSR performance as
an endorsement of the disciplined, returns-focused value proposition we launched
in late 2016.
At that time, we implemented a strategy that we believe remains the right one for
the E&P sector. Although our business is opportunity-rich, it’s also mature, capital-
intensive and cyclical. In embracing these realities, we’ve led the industry in setting
clear priorities for how we’ll allocate cash to generate superior returns through cycles.
Designing a value proposition is one thing; delivering on it is another. Over the past two years, we’ve taken
numerous actions to improve the underlying quality of our business. We’ve significantly lowered our sustaining
price and strengthened our balance sheet. We’ve grown our resource base with a cost of supply less than $40 per
barrel West Texas Intermediate. We’ve delivered competitive per-share growth, not chased absolute growth.
We’ve returned a distinctive portion of cash flows to shareholders, kept costs in check and generated one of our
industry’s most competitive financial returns. Our 2018 results demonstrate that our value proposition is working.
During the year ConocoPhillips achieved:
• Financial returns that surpassed the returns from just a few years ago when Brent prices averaged more than
50 percent higher;
• Cash from operations that exceeded capital spending by $5.5 billion;
• Higher-than-targeted production growth on a per debt-adjusted share basis;
• Debt reduction of $4.7 billion, thus achieving our $15 billion total debt target 18 months early;
• 35 percent payout of cash from operations to shareholders via our dividend and $3 billion of share buybacks;
• Portfolio enhancements through exploration success and acquisitions in Alaska, acreage additions in the Lower 48
and Canada, and proceeds from non-core asset dispositions of $1.1 billion;
• 147 percent total reserve replacement, and 109 percent organic reserve replacement excluding asset transactions;
• And year-end reserves of 5.3 billion barrels of oil equivalent.
Importantly, we delivered these milestones safely and sustainably, while engaging with our many stakeholders. 2018
was a gratifying year and we’re excited about our opportunities in 2019. We’ll maintain our disciplined approach
with a $6.1 billion capital budget, a focus on per-share growth, an increasing dividend, and $3 billion in planned
share buybacks for the third straight year. Operationally, we’ll conduct exploration, appraisal and development in
the Lower 48, Alaska, Canada and Europe, with major project decisions pending in China, Australia and elsewhere.
We believe that our 2019 operating plan reflects what you’ve come to expect from us. It’s consistent with our
priorities, focused on long-term value creation and underpinned by our commitment to strong execution. This is
our formula for delivering superior returns to shareholders through the cycles, and for many years to come. Our
formula works and we’re sticking to it.
We appreciate our employees and shareholders for their ongoing support of ConocoPhillips.
Ryan M. Lance
Chairman and Chief Executive Officer
Feb. 19, 2019
Charles E. Bunch
Former Chairman and Chief Executive
Officer, PPG Industries, Inc.
Ryan M. Lance
Chairman and Chief Executive Officer,
ConocoPhillips
Admiral William H. McRaven
Retired U.S. Navy Four-Star Admiral (SEAL)
Sharmila Mulligan
Founder and Chief Executive Officer,
ClearStory Data Inc.
Arjun N. Murti
Senior Advisor, Warburg Pincus
Robert A. Niblock
Former Chairman, President and Chief
Executive Officer, Lowe’s Companies, Inc.
Harald J. Norvik
Former Chairman, President and
Chief Executive Officer, Statoil
Caroline Maury Devine
Former President and Managing Director
of a Norwegian affiliate of ExxonMobil
John V. Faraci
Former Chairman and Chief Executive
Officer, International Paper Company
Jody Freeman
Archibald Cox Professor of Law,
Harvard Law School
Gay Huey Evans OBE
Member of Her Majesty’s Treasury Board,
Sub-Committee and Nominations
Committee
Jeffrey A. Joerres
Former Executive Chairman and Chief
Executive Officer, ManpowerGroup Inc.
EXECUTIVE LEADERSHIP TEAM
(As of Feb. 19, 2019)
Ryan M. Lance
Chairman and Chief Executive Officer
Michael D. Hatfield
President, Alaska, Canada and Europe
Matt J. Fox
Executive Vice President and
Chief Operating Officer
Don E. Wallette, Jr.
Executive Vice President and
Chief Financial Officer
William L. Bullock, Jr.
President, Asia Pacific & Middle East
Ellen R. DeSanctis
Senior Vice President, Corporate Relations
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
Certain 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’ 2018 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.
Use of Non-GAAP Financial Information – This annual report includes the non-GAAP term “cash from operations” to help facilitate
comparisons of company operating performance across periods and with peer companies. Cash from operations is defined as cash provided
by operating activities excluding the impact of operating working capital. 2018 cash provided by operating activities is $12.9 billion. Excluding
operating working capital of $0.6 billion, cash from operations is $12.3 billion.
EXPLORE
CONOCOPHILLIPS
Fact Sheets
The 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.
Sustainability Report
Our 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 Report
Our 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.
ConocoPhillips has procedures
in place that minimize the
environmental risk and impact
of drilling and development.
Additionally, the company has
voluntarily set a long-term
target to reduce its greenhouse
gas emissions intensity by
5 to 15 percent by 2030.
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