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CONOCOPHILLIPS - Quarter Report: 2020 September (Form 10-Q)

COP20203q10q
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
FORM
10-Q
 
(Mark One)
[
X
]
QUARTERLY
 
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
 
September 30, 2020
 
 
or
[
 
]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
 
 
to
 
Commission file number:
 
 
001-32395
 
 
ConocoPhillips
 
(Exact name of registrant as specified in its charter)
 
Delaware
01-0562944
(State or other jurisdiction of incorporation
or organization)
(I.R.S. Employer
Identification No.)
 
925 N. Eldridge Parkway
Houston
,
TX
77079
 
(Address of principal executive offices)
 
(Zip Code)
 
281
-
293-1000
 
 
(Registrant's telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the
 
Act:
Title of each class
Trading symbols
Name of each exchange on which registered
Common Stock, $.01 Par Value
COP
New York Stock Exchange
7% Debentures due 2029
CUSIP—718507BK1
New York Stock Exchange
 
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.
 
Yes
 
[x] No [
 
]
 
Indicate by check mark whether the registrant
 
has submitted electronically every Interactive
 
Data File required
to be submitted pursuant to Rule 405 of Regulation
 
S-T
 
(§232.405 of this chapter) during the preceding
 
12
months (or for such shorter period that the registrant
 
was required to submit such files).
 
Yes
 
[x] No [
 
]
 
Indicate by check mark whether the registrant
 
is a large accelerated filer, an accelerated filer, a non-accelerated
filer, a smaller reporting company, or an emerging growth company.
 
See the definitions of “large accelerated
filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in
 
Rule 12b-2 of the
Exchange Act.
 
 
Large accelerated filer
 
[x]
 
Accelerated filer [
 
]
 
Non-accelerated filer [
 
]
 
Smaller reporting company
 
[
 
]
Emerging growth company
 
[
 
]
 
If an emerging growth company, indicate by check mark if the registrant has elected
 
not to use the extended
transition period for complying with any new or
 
revised financial accounting standards
 
provided pursuant to
Section 13(a) of the Exchange Act. [
 
]
 
Indicate by check mark whether the registrant
 
is a shell company (as defined in Rule 12b-2 of the
 
Exchange
Act).
 
Yes
 
[
 
]
No
 
[x]
 
The registrant had
1,072,741,643
 
shares of common stock, $.01 par value, outstanding
 
at September 30, 2020.
 
CONOCOPHILLIPS
 
TABLE OF CONTENTS
 
 
 
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1
Commonly Used Abbreviations
 
The following industry-specific, accounting and
 
other terms, and abbreviations may be commonly
 
used in this
report.
 
Currencies
Accounting
$ or USD
U.S. dollar
ARO
asset retirement obligation
CAD
Canadian dollar
ASC
accounting standards codification
EUR
Euro
ASU
accounting standards update
GBP
British pound
DD&A
depreciation, depletion and
amortization
Units of Measurement
FASB
Financial Accounting Standards
BBL
barrel
Board
BCF
billion cubic feet
FIFO
first-in, first-out
BOE
barrels of oil equivalent
G&A
general and administrative
MBD
thousands of barrels per day
GAAP
generally accepted accounting
 
MCF
thousand cubic feet
principles
MBOD
thousand barrels of oil per day
LIFO
last-in, first-out
MM
million
NPNS
normal purchase normal sale
MMBOE
million barrels of oil equivalent
PP&E
properties, plants and equipment
MMBOD
million barrels of oil per day
SAB
staff accounting bulletin
MBOED
thousands of barrels of oil
 
VIE
variable interest entity
equivalent per day
MMBTU
million British thermal units
Miscellaneous
MMCFD
million cubic feet per day
EPA
Environmental Protection Agency
ESG
Environmental, Social and
Corporate Governance
Industry
EU
European Union
CBM
coalbed methane
FERC
Federal Energy Regulatory
 
E&P
exploration and production
Commission
FEED
front-end engineering and design
GHG
greenhouse gas
FPS
floating production system
HSE
health, safety and environment
FPSO
floating production, storage and
ICC
International Chamber of
 
offloading
Commerce
JOA
joint operating agreement
ICSID
World Bank’s
 
International
 
LNG
liquefied natural gas
Centre for Settlement of
NGLs
natural gas liquids
Investment Disputes
OPEC
Organization of Petroleum
 
IRS
Internal Revenue Service
Exporting Countries
OTC
over-the-counter
PSC
production sharing contract
NYSE
New York Stock Exchange
PUDs
proved undeveloped reserves
SEC
U.S. Securities and Exchange
 
SAGD
steam-assisted gravity drainage
Commission
WCS
Western Canada Select
TSR
total shareholder return
WTI
West Texas
 
Intermediate
U.K.
United Kingdom
U.S.
United States of America
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2
PART
 
I.
 
FINANCIAL INFORMATION
 
Item 1.
 
FINANCIAL STATEMENTS
 
Consolidated Income Statement
ConocoPhillips
 
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Revenues and Other Income
Sales and other operating revenues
$
4,386
7,756
13,293
24,859
Equity in earnings of affiliates
35
290
346
651
Gain (loss) on dispositions
(3)
1,785
551
1,884
Other income (loss)
(38)
262
(983)
1,136
Total Revenues and
 
Other Income
4,380
10,093
13,207
28,530
Costs and Expenses
Purchased commodities
1,839
2,710
5,630
9,059
Production and operating expenses
963
1,331
3,183
4,020
Selling, general and administrative expenses
96
87
249
369
Exploration expenses
125
360
410
592
Depreciation, depletion and amortization
1,411
1,566
3,980
4,602
Impairments
2
24
521
26
Taxes other than
 
income taxes
179
237
570
706
Accretion on discounted liabilities
62
86
195
259
Interest and debt expense
200
184
604
582
Foreign currency transaction (gain) loss
(5)
(21)
(88)
19
Other expenses
20
36
7
58
Total Costs and Expenses
4,892
6,600
15,261
20,292
Income (loss) before income taxes
(512)
3,493
(2,054)
8,238
Income tax provision (benefit)
(62)
422
(171)
1,724
Net income (loss)
(450)
3,071
(1,883)
6,514
Less: net income attributable to noncontrolling interests
-
(15)
(46)
(45)
Net Income (Loss) Attributable to ConocoPhillips
$
(450)
3,056
(1,929)
6,469
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
(0.42)
2.76
(1.79)
5.75
Diluted
(0.42)
2.74
(1.79)
5.72
Average Common
 
Shares Outstanding
(in thousands)
Basic
1,077,377
1,108,555
1,079,525
1,124,558
Diluted
1,077,377
1,113,250
1,079,525
1,131,034
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3
 
Consolidated Statement of Comprehensive Income
ConocoPhillips
 
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Net Income (Loss)
$
(450)
3,071
(1,883)
6,514
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior
service credit included in net income (loss)
(8)
(8)
(24)
(26)
Net actuarial loss arising during the period
(78)
(149)
(73)
(149)
Reclassification adjustment for amortization of net actuarial
losses included in net income (loss)
45
56
81
114
Nonsponsored plans
-
(1)
-
(1)
Income taxes on defined benefit plans
10
30
3
20
Defined benefit plans, net of tax
(31)
(72)
(13)
(42)
Unrealized holding gain on securities
-
-
3
-
Income taxes on unrealized holding gain on securities
-
-
(1)
-
Unrealized holding gain on securities, net of tax
-
-
2
-
Foreign currency translation adjustments
188
247
(302)
493
Income taxes on foreign currency translation adjustments
2
(2)
4
(2)
Foreign currency translation adjustments, net of tax
190
245
(298)
491
Other Comprehensive Income (Loss), Net
 
of Tax
159
173
(309)
449
Comprehensive Income (Loss)
(291)
3,244
(2,192)
6,963
Less: comprehensive income attributable to noncontrolling
 
interests
-
(15)
(46)
(45)
Comprehensive Income (Loss) Attributable to
 
ConocoPhillips
$
(291)
3,229
(2,238)
6,918
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4
 
 
Consolidated Balance Sheet
ConocoPhillips
 
Millions of Dollars
September 30
December 31
2020
2019
Assets
Cash and cash equivalents
$
2,490
5,088
Short-term investments
4,032
3,028
Accounts and notes receivable (net of allowance of $
4
 
and $
13
, respectively)
1,984
3,267
Accounts and notes receivable—related parties
135
134
Investment in Cenovus Energy
809
2,111
Inventories
1,034
1,026
Prepaid expenses and other current assets
575
2,259
Total Current
 
Assets
11,059
16,913
Investments and long-term receivables
8,295
8,687
Loans and advances—related parties
114
219
Net properties, plants and equipment
(net of accumulated DD&A of $
58,726
 
and $
55,477
, respectively)
41,269
42,269
Other assets
2,420
2,426
Total Assets
$
63,157
70,514
Liabilities
Accounts payable
$
2,217
3,176
Accounts payable—related parties
22
24
Short-term debt
482
105
Accrued income and other taxes
339
1,030
Employee benefit obligations
469
663
Other accruals
1,111
2,045
Total Current
 
Liabilities
4,640
7,043
Long-term debt
14,905
14,790
Asset retirement obligations and accrued environmental
 
costs
5,651
5,352
Deferred income taxes
3,854
4,634
Employee benefit obligations
1,661
1,781
Other liabilities and deferred credits
1,663
1,864
Total Liabilities
32,374
35,464
Equity
Common stock (
2,500,000,000
 
shares authorized at $
0.01
 
par value)
Issued (2020—
1,798,738,512
 
shares; 2019—
1,795,652,203
 
shares)
Par value
18
18
Capital in excess of par
47,113
46,983
Treasury stock (at cost: 2020—
725,996,869
 
shares; 2019—
710,783,814
 
shares)
(47,130)
(46,405)
Accumulated other comprehensive loss
(5,666)
(5,357)
Retained earnings
36,448
39,742
Total Common
 
Stockholders’ Equity
30,783
34,981
Noncontrolling interests
-
69
Total Equity
30,783
35,050
Total Liabilities and
 
Equity
$
63,157
70,514
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5
 
 
Consolidated Statement of Cash Flows
ConocoPhillips
 
Millions of Dollars
Nine Months Ended
September 30
2020
2019
Cash Flows From Operating Activities
Net income (loss)
$
(1,883)
6,514
Adjustments to reconcile net income (loss) to net cash provided
 
by operating
activities
Depreciation, depletion and amortization
3,980
4,602
Impairments
521
26
Dry hole costs and leasehold impairments
114
361
Accretion on discounted liabilities
195
259
Deferred taxes
(428)
(304)
Undistributed equity earnings
450
260
Gain on dispositions
(551)
(1,884)
Unrealized (gain) loss on investment in Cenovus Energy
1,302
(489)
Other
(188)
(331)
Working
 
capital adjustments
Decrease in accounts and notes receivable
1,132
333
Increase in inventories
(74)
(2)
Increase in prepaid expenses and other current assets
(49)
(29)
Decrease in accounts payable
(583)
(476)
Decrease in taxes and other accruals
(808)
(718)
Net Cash Provided by Operating Activities
3,130
8,122
Cash Flows From Investing Activities
Capital expenditures and investments
(3,657)
(5,041)
Working
 
capital changes associated with investing activities
(229)
17
Proceeds from asset dispositions
1,312
2,920
Net purchases of investments
(1,089)
(665)
Collection of advances/loans—related parties
116
127
Other
(31)
(146)
Net Cash Used in Investing Activities
(3,578)
(2,788)
Cash Flows From Financing Activities
Issuance of debt
300
-
Repayment of debt
(234)
(59)
Issuance of company common stock
(2)
(39)
Repurchase of company common stock
(726)
(2,751)
Dividends paid
 
(1,367)
(1,037)
Other
(27)
(73)
Net Cash Used in Financing Activities
(2,056)
(3,959)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
 
Restricted Cash
(62)
(68)
Net Change in Cash, Cash Equivalents and Restricted Cash
(2,566)
1,307
Cash, cash equivalents and restricted cash at beginning
 
of period
5,362
6,151
Cash, Cash Equivalents and Restricted Cash at End of Period
$
2,796
7,458
Restricted cash of $
91
 
million and $
215
 
million are included in the "Prepaid expenses and other current assets" and "Other assets" lines,
respectively, of our Consolidated Balance Sheet as of September 30, 2020.
Restricted cash of $
90
 
million and $
184
 
million are included in the "Prepaid expenses and other current assets" and "Other assets" lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2019.
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
6
 
Notes to Consolidated Financial Statements
ConocoPhillips
 
 
Note 1—Basis of Presentation
 
The interim-period financial information
 
presented in the financial statements included
 
in this report is
unaudited and, in the opinion of management,
 
includes all known accruals and adjustments
 
necessary for a fair
presentation of the consolidated financial
 
position of ConocoPhillips and its results
 
of operations and cash
flows for such periods.
 
All such adjustments are of a normal and recurring
 
nature unless otherwise disclosed.
Certain notes and other information have been
 
condensed or omitted from the interim
 
financial statements
included in this report.
 
Therefore, these financial statements should
 
be read in conjunction with the
consolidated financial statements and notes included
 
in our 2019 Annual Report on Form
 
10-K.
 
The unrealized (gain) loss on investment in Cenovus
 
Energy included on our consolidated statement of cash
flows, previously reflected on the line item
 
“Other” within net cash provided by operating
 
activities, has been
reclassified in the comparative period to conform
 
with the current period’s presentation.
 
 
 
Note 2—Changes in Accounting Principles
 
We
adopted
 
the provisions of
FASB ASU No. 2016-13
, “Measurement of Credit Losses on Financial
Instruments,” (ASC Topic 326) and its amendments,
beginning
January 1, 2020
.
 
This ASU, as amended, sets
forth the current expected credit loss model,
 
a new forward-looking impairment model
 
for certain financial
instruments measured at amortized cost basis
 
based on expected losses rather than incurred losses.
 
This ASU,
as amended, which primarily applies to our accounts
 
receivable, also requires credit losses related
 
to available-
for-sale debt securities to be recorded through an allowance
 
for credit losses.
 
The adoption of this ASU did
not have a material impact to our financial statements.
 
The majority of our receivables are due within
 
30 days
or less.
 
We monitor the credit quality of our counterparties through review of collections,
 
credit ratings, and
other analyses.
 
We develop our estimated allowance for credit losses primarily using an aging method
 
and
analyses of historical loss rates as well as consideration
 
of current and future conditions that could
 
impact our
counterparties’ credit quality and liquidity.
 
 
Note 3—Inventories
Inventories consisted of the following:
Millions of Dollars
September 30
 
December 31
2020
2019
Crude oil and natural gas
$
503
472
Materials and supplies
531
554
$
1,034
1,026
 
 
Inventories valued on the LIFO basis totaled
 
$
373
 
million and $
286
 
million at September 30, 2020 and
December 31, 2019, respectively.
 
Due to a precipitous decline in commodity prices
 
beginning in March this
year, we recorded a lower of cost or market adjustment in the first
 
quarter of 2020 of $
228
 
million to our crude
oil and natural gas inventories. The adjustment
 
was included in the “Purchased commodities”
 
line on our
consolidated income statement.
 
Commodity prices have improved since the first
 
quarter.
 
 
7
Note 4—Asset Acquisitions and Dispositions
 
 
Asset Acquisition
In August 2020, we completed the acquisition
 
of additional Montney acreage in Canada from Kelt
 
Exploration
Ltd. for $
382
 
million after customary adjustments, plus the
 
assumption of $
31
 
million in financing obligations
associated with partially owned infrastructure.
 
This acquisition consisted primarily
 
of undeveloped properties
and included
140,000
 
net acres in the liquids-rich Inga Fireweed asset
 
Montney zone, which is directly
adjacent to our existing Montney position.
 
The transaction increases our Montney acreage
 
position to
295,000
net acres with a
100
 
percent working interest.
 
This agreement was accounted for as an asset acquisition
resulting in the recognition of $
490
 
million of PP&E; $
77
 
million of ARO and accrued environmental costs;
and $
31
 
million of financing obligations recorded primarily
 
to long-term debt.
 
Results of operations for the
Montney are reported in our Canada segment.
 
Assets Sold
In May 2020, we completed the divestiture
 
of our subsidiaries that held our Australia-West assets and
operations, and based on an effective date of January
 
1, 2019, we received proceeds of $
765
 
million with an
additional $
200
 
million due upon final investment decision
 
of the proposed Barossa development project.
 
In
the nine-month period of 2020, we recognized a before-tax
 
gain of $
587
 
million related to this transaction.
 
At
the time of disposition, the net carrying value of
 
the subsidiaries sold was approximately
 
$
0.2
 
billion,
excluding $
0.5
 
billion of cash.
 
The net carrying value consisted primarily
 
of $
1.3
 
billion of PP&E and $
0.1
billion of other current assets offset by $
0.7
 
billion of ARO, $
0.3
 
billion of deferred tax liabilities, and $
0.2
billion of other liabilities.
 
The before-tax earnings associated with the subsidiaries
 
sold, including the gain on
disposition noted above, were $
851
 
million and $
222
 
million for the nine-month periods ended September
 
30,
2020 and 2019, respectively.
 
Production from the beginning of the year through the
 
disposition date in May
2020 averaged
43
 
MBOED.
 
Results of operations for the subsidiaries sold
 
are reported in our
Asia Pacific
segment.
 
In March 2020, we completed the sale of our Niobrara
 
interests for approximately $
359
 
million after
customary adjustments and recognized a before-tax
 
loss on disposition of $
38
 
million.
 
At the time of
disposition, our interest in Niobrara had a net carrying
 
value of $
397
 
million, consisting primarily of $
433
million of PP&E and $
34
 
million of ARO.
 
The before-tax earnings associated with our
 
interests in Niobrara,
including the loss on disposition, were a loss of $
22
 
million and $
7
 
million for the nine-month periods ended
September 30, 2020 and 2019, respectively.
 
 
In February 2020, we sold our Waddell Ranch interests in the Permian Basin for $
184
 
million after customary
adjustments.
 
No
 
gain or loss was recognized on the sale.
 
 
Production from the disposed Niobrara and Waddell Ranch interests in our
Lower 48
 
segment averaged
15
MBOED in 2019.
 
 
Note 5—Investments, Loans and Long-Term Receivables
 
 
Australia Pacific LNG Pty Ltd (APLNG)
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.
 
All amounts were drawn from the facility.
 
APLNG made its first principal and
interest repayment in March 2017 and is scheduled
 
to make
bi-annual
 
payments until
March 2029
.
 
 
APLNG made a voluntary repayment of $
1.4
 
billion to the Export-Import Bank of China
 
in September 2018.
 
At the same time, APLNG obtained a United
 
States Private Placement (USPP) bond facility
 
of $
1.4
 
billion.
 
APLNG made its first interest payment related to
 
this facility in March 2019, and principal
 
payments are
scheduled to commence in September 2023, with
bi-annual
 
payments due on the facility until
September 2030
.
 
8
 
During the first quarter of 2019, APLNG refinanced
 
$
3.2
 
billion of existing project finance debt through two
transactions.
 
As a result of the first transaction, APLNG obtained
 
a commercial bank facility of $
2.6
 
billion.
 
APLNG made its first principal and interest
 
repayment in September 2019 with
bi-annual
 
payments due on the
facility until
March 2028
.
 
Through the second transaction, APLNG obtained
 
a USPP bond facility of $
0.6
billion.
 
APLNG made its first interest payment in September
 
2019, and principal payments are scheduled
 
to
commence in September 2023, with
bi-annual
 
payments due on the facility until
 
September 2030.
 
In conjunction with the $
3.2
 
billion debt obtained during the first quarter
 
of 2019 to refinance existing project
finance debt, APLNG made voluntary repayments
 
of $
2.2
 
billion and $
1.0
 
billion to a syndicate of Australian
and international commercial banks and the Export-Import
 
Bank of China, respectively.
 
At September 30, 2020, a balance of $
6.2
 
billion was outstanding on the facilities.
 
See Note 11—Guarantees,
for additional information.
 
At September 30, 2020, the carrying value of our
 
equity method investment in APLNG was $
6,877
 
million.
 
The balance is included in the “Investments
 
and long-term receivables” line on our consolidated
 
balance sheet.
 
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
made to certain affiliated and non-affiliated companies.
 
At September 30, 2020, significant loans
 
to affiliated
companies included $
219
 
million in project financing to Qatar Liquefied
 
Gas Company Limited (3).
 
On our consolidated balance sheet, the long-term
 
portion of these loans is included in the “Loans
 
and
advances—related parties” line, while the short-term
 
portion is in the “Accounts and notes receivable—related
parties” line.
 
 
Note 6—Investment in Cenovus Energy
 
On May 17, 2017, we completed the sale of our
50
 
percent nonoperated interest in the FCCL Partnership,
 
as
well as the majority of our western Canada gas assets,
 
to Cenovus Energy.
 
Consideration for the transaction
included
208
 
million Cenovus Energy common shares, which,
 
at closing, approximated
16.9
 
percent of issued
and outstanding Cenovus Energy common stock.
 
The fair value and cost basis of our investment
 
in
208
million Cenovus Energy common shares was $
1.96
 
billion based on a price of $
9.41
 
per share on the NYSE on
the closing date.
 
At September 30, 2020, the investment included on
 
our consolidated balance sheet was $
809
 
million and is
carried at fair value.
 
The fair value of the
208
 
million Cenovus Energy common shares reflects
 
the closing
price of $
3.89
 
per share on the NYSE on the last trading day
 
of the quarter, a decrease of $
1.30
 
billion from its
fair value of $
2.11
 
billion at year-end 2019.
 
For the three- and nine-month periods ended September
 
30, 2020,
we recorded an unrealized loss of $
162
 
million and $
1.30
 
billion, respectively.
 
For the three- and nine-month
periods ended September 30, 2019, we recorded
 
an unrealized gain of $
116
 
million and $
489
 
million,
respectively.
 
The unrealized gains and losses are recorded within
 
the “Other income (loss)” line of our
consolidated income statement and are related to the
 
shares held at the reporting date.
 
See Note 14—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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
Note 7—Suspended Wells
 
The capitalized cost of suspended wells at September
 
30, 2020, was $
711
 
million, a decrease of $
309
 
million
from year-end 2019 primarily related to our Australia-West divestiture.
 
See Note 4—Asset Acquisitions and
Dispositions,
 
for additional information.
 
Of the well costs capitalized for more than one
 
year as of December
31, 2019, $
20
 
million was charged to dry hole expense during
 
the first nine months of 2020 primarily for
one
suspended well in the Kamunsu East Field offshore Malaysia.
 
 
Note 8—Impairments
During the three-
 
and nine-month periods ended September 30, 2020
 
and 2019, we recognized before-tax
impairment charges within the following segments:
Millions of Dollars
 
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Lower 48
$
1
22
514
22
Europe, Middle East and North Africa
1
2
7
4
$
2
24
521
26
 
 
We perform impairment reviews when triggering events arise that may impact the
 
fair value of our assets or
investments.
 
 
We observed volatility in commodity prices during the first nine-months of 2020.
 
A decline in commodity
prices beginning in March prompted us to evaluate
 
the recoverability of the carrying value of our assets
 
and
whether an other than temporary impairment
 
occurred for investments in our portfolio.
 
For certain non-core
natural gas assets in the Lower 48, a significant decrease
 
in the outlook for current and long-term natural
 
gas
prices resulted in a decline in the estimated fair
 
values to amounts below carrying value.
 
Accordingly, in the
first quarter of 2020, we recorded impairments of
 
$
511
 
million related to these non-core natural gas assets,
primarily for the Wind River Basin operations area consisting of
 
developed properties in the Madden Field and
the Lost Cabin Gas Plant, which were written down
 
to fair value.
 
See Note 14—Fair Value Measurement, for
additional information.
 
A sustained decline in the current and long-term
 
outlook on commodity prices could trigger
 
additional
impairment reviews and possibly result in
 
future impairment charges.
 
The charges discussed below are included in the “Exploration
 
expenses” line on our consolidated income
statement and are not reflected in the table above.
 
 
We recorded a before-tax impairment in the first quarter of 2020 of $
31
 
million in our Asia Pacific segment
related to the associated carrying value of capitalized
 
undeveloped leasehold costs for the Kamunsu East
 
Field
in Malaysia that is no longer in our development
 
plans.
 
 
In the third quarter of 2019, we recorded a before-tax
 
impairment of $
141
 
million in our Lower 48 segment for
the associated carrying value of capitalized undeveloped
 
leasehold costs due to our decision to discontinue
exploration activities in the Central Louisiana Austin
 
Chalk trend.
 
10
Note 9—Debt
 
 
 
Our debt balance as of September 30, 2020 was $
15,387
 
million compared with $
14,895
 
million at December
31, 2019.
 
 
Our revolving credit facility provides a total commitment
 
of $
6.0
 
billion and expires in
May 2023
.
 
Our
revolving credit facility may be used for direct
 
bank borrowings, the issuance of letters of credit
 
totaling up to
$
500
 
million, or as support for our commercial paper
 
program.
 
Our commercial paper program consists
 
of the
ConocoPhillips Company $
6.0
 
billion program, primarily a funding source for
 
short-term working capital
needs.
 
Commercial paper maturities are generally limited
 
to
90 days
.
 
 
We issued $
300
 
million of commercial paper in the third
 
quarter of 2020, which is included in short-term
 
debt
on our consolidated balance sheet.
 
With $
300
 
million of commercial paper outstanding and
no
 
direct
borrowings or letters of credit, we had $
5.7
 
billion in available capacity under the revolving
 
credit facility at
September 30, 2020.
 
We had
no
 
direct outstanding borrowings, letters of credit,
 
nor outstanding commercial
paper as of December 31, 2019.
 
 
In October 2020, S&P affirmed its “A” rating on our senior long-term debt and revised its outlook to “stable”
from “negative,”
Fitch affirmed its rating of “A” with a “stable” outlook
and Moody’s affirmed its rating of
“A3” with a “stable” outlook.
 
At September 30, 2020, 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 bondholders
 
on any business
day.
 
If they are ever redeemed, we have the ability
 
and intent to refinance on a long-term basis,
 
therefore, the
VRDBs are included in the “Long-term debt” line
 
on our consolidated balance sheet.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11
Note 10—Changes in Equity
Millions of Dollars
Attributable to ConocoPhillips
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-
Controlling
Interests
Total
For the three months ended September 30, 2020
Balances at June 30, 2020
$
18
47,079
(47,130)
(5,825)
37,351
31,493
Net loss
(450)
(450)
Other comprehensive income
159
159
Dividends paid ($
0.42
 
per common share)
(454)
(454)
Distributed under benefit plans
34
34
Other
1
1
Balances at September 30, 2020
$
18
47,113
(47,130)
(5,666)
36,448
30,783
For the nine months ended September 30,
 
2020
Balances at December 31, 2019
$
18
46,983
(46,405)
(5,357)
39,742
69
35,050
Net income (loss)
(1,929)
46
(1,883)
Other comprehensive loss
(309)
(309)
Dividends paid ($
1.26
 
per common share)
(1,367)
(1,367)
Repurchase of company common stock
(726)
(726)
Distributions to noncontrolling interests and other
(32)
(32)
Disposition
(84)
(84)
Distributed under benefit plans
130
130
Other
1
2
1
4
Balances at September 30, 2020
$
18
47,113
(47,130)
(5,666)
36,448
-
30,783
Millions of Dollars
Attributable to ConocoPhillips
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-
Controlling
Interests
Total
For the three months ended September 30, 2019
Balances at June 30, 2019
$
18
46,922
(44,906)
(5,827)
36,769
98
33,074
Net income
3,056
15
3,071
Other comprehensive income
173
173
Dividends paid ($
0.31
 
per common share)
(341)
(341)
Repurchase of company common stock
(749)
(749)
Distributions to noncontrolling interests and other
(20)
(20)
Distributed under benefit plans
32
32
Other
(1)
(1)
Balances at September 30, 2019
$
18
46,954
(45,656)
(5,654)
39,484
93
35,239
For the nine months ended September 30,
 
2019
Balances at December 31, 2018
$
18
46,879
(42,905)
(6,063)
34,010
125
32,064
Net income
6,469
45
6,514
Other comprehensive income
449
449
Dividends paid ($
0.92
 
per common share)
(1,037)
(1,037)
Repurchase of company common stock
(2,751)
(2,751)
Distributions to noncontrolling interests and other
(80)
(80)
Distributed under benefit plans
75
75
Changes in Accounting Principles*
(40)
40
-
Other
2
3
5
Balances at September 30, 2019
$
18
46,954
(45,656)
(5,654)
39,484
93
35,239
*Cumulative effect of the adoption of ASU No. 2018-02,
 
"Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income."
 
12
Note 11—Guarantees
 
At September 30, 2020, 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 September 30, 2020, 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
September 2020 exchange rates:
 
 
 
During the third quarter of 2016, we issued a guarantee
 
to facilitate the withdrawal of our pro-rata
portion of the funds in a project finance reserve
 
account.
 
We estimate the remaining term of this
guarantee is
10 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 September 30, 2020, the carrying value of
 
this guarantee was approximately $
14
million.
 
 
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
1 to 22 years
.
 
Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated
 
to be $
720
 
million
($
1.3
 
billion in the event of intentional or reckless
 
breach), and would become payable if
 
APLNG fails
to meet its obligations under these agreements and
 
the obligations cannot otherwise be mitigated.
 
Future payments are considered unlikely, as the payments, or cost of volume
 
delivery, would only be
triggered if APLNG does not have enough natural
 
gas to meet these sales commitments and if
 
the
co-venturers do not make necessary equity contributions
 
into APLNG.
 
 
 
We have guaranteed the performance of APLNG with regard to certain other contracts
 
executed in
connection with the project’s continued development.
 
The guarantees have remaining terms
 
of
16 to
25 years or the life of the venture
.
 
Our maximum potential amount of future payments
 
related to these
guarantees is approximately $
120
 
million and would become payable if APLNG
 
does not perform.
 
At
September 30, 2020, the carrying value of these
 
guarantees was approximately $
7
 
million.
 
 
Other Guarantees
 
We have other guarantees with maximum future potential payment amounts totaling
 
approximately
 
$
750
 
million, which consist primarily of
 
guarantees of the residual value of leased office buildings,
 
guarantees
of the residual value of corporate aircrafts,
 
and a guarantee for our portion of a joint venture’s project finance
reserve accounts.
 
These guarantees have remaining terms
 
of
1 to 5 years
 
and would become payable if certain
asset values are lower than guaranteed amounts at
 
the end of the lease or contract term, business conditions
decline at guaranteed entities, or as a result of nonperformance
 
of contractual terms by guaranteed parties.
 
At September 30, 2020, the carrying value of these
 
guarantees was approximately $
11
 
million.
 
 
Indemnifications
Over the years, we have entered into agreements to
 
sell ownership interests in certain legal
 
entities, joint
ventures and assets that gave rise to qualifying
 
indemnifications.
 
These agreements include indemnifications
for taxes and environmental liabilities.
 
The majority of these indemnifications are related
 
to tax issues and the
majority of these expire in 2021.
 
Those related to environmental issues have terms
 
that are generally indefinite
and the maximum amounts of future payments are
 
generally unlimited.
 
The carrying amount recorded for
these indemnification obligations at September 30,
 
2020, was approximately $
50
 
million.
 
We amortize the
 
13
indemnification liability over the relevant time
 
period the indemnity is in effect, 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.
 
For additional information about environmental
 
liabilities, see Note 12—Contingencies and
Commitments.
 
 
 
Note 12—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 low
end of the range is accrued.
 
We do not reduce these liabilities for potential insurance or third-party recoveries.
 
We accrue receivables for insurance or other third-party recoveries when applicable.
 
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.
 
As we learn new facts concerning contingencies,
 
we reassess our position
both with respect to accrued liabilities
 
and other potential exposures.
 
Estimates particularly sensitive to future
changes include contingent liabilities
 
recorded for environmental remediation, tax and legal
 
matters.
 
Estimated future environmental remediation
 
costs are subject to change due to such factors
 
as the uncertain
magnitude of cleanup costs, the unknown time
 
and extent of such remedial actions that
 
may be required, and
the determination of our liability in proportion
 
to that of other responsible parties.
 
Estimated future costs
related to tax and legal matters are subject to
 
change as events evolve and as additional
 
information becomes
available during the administrative and litigation
 
processes.
 
Environmental
We are subject to international, federal, state and local environmental laws and regulations.
 
When we prepare
our consolidated financial statements, we record
 
accruals for environmental liabilities based on management’s
best estimates, using all information that is
 
available at the time.
 
We measure estimates and base liabilities on
currently available facts, existing technology, and presently enacted laws and
 
regulations, taking into account
stakeholder and business considerations.
 
When measuring environmental liabilities,
 
we also consider our prior
experience in remediation of contaminated sites,
 
other companies’ cleanup experience, and data released
 
by
the U.S. EPA or other organizations.
 
We consider unasserted claims in our determination of environmental
liabilities, and we accrue them in the period they are
 
both probable and reasonably estimable.
 
Although liability of those potentially responsible
 
for environmental remediation costs is generally
 
joint and
several for federal sites and frequently so for other
 
sites, we are usually only one of many companies
 
cited at a
particular site.
 
Due to the joint and several liabilities, we could
 
be responsible for all cleanup costs related to
any site at which we have been designated as a
 
potentially responsible party.
 
We have been successful to date
in sharing cleanup costs with other financially
 
sound companies.
 
Many of the sites at which we are potentially
responsible are still under investigation by the EPA or the agency concerned.
 
Prior to actual cleanup, those
potentially responsible normally assess the
 
site conditions, apportion responsibility and determine
 
the
appropriate remediation.
 
In some instances, we may have no liability
 
or may attain a settlement of liability.
 
Where it appears that other potentially responsible
 
parties may be financially unable to bear their
 
proportional
share, we consider this inability in estimating
 
our potential liability, and we adjust our accruals accordingly.
 
 
14
As a result of various acquisitions in the past,
 
we assumed certain environmental obligations.
 
Some of these
environmental obligations are mitigated by indemnifications
 
made by others for our benefit, and some of the
indemnifications are subject to dollar limits
 
and time limits.
 
We are currently participating in environmental assessments and cleanups at numerous
 
federal Superfund and
comparable state and international sites.
 
After an assessment of environmental exposures
 
for cleanup and
other costs, we make accruals on an undiscounted
 
basis (except those acquired in a purchase
 
business
combination, which we record on a discounted basis)
 
for planned investigation and remediation activities
 
for
sites where it is probable future costs will be incurred
 
and these costs can be reasonably estimated.
 
We have
not reduced these accruals for possible insurance recoveries.
 
At September 30, 2020, our balance sheet included
 
a total environmental accrual of $
177
 
million, compared
with $
171
 
million at December 31, 2019, for remediation
 
activities in the U.S. and Canada.
 
We expect to
incur a substantial amount of these expenditures
 
within the next
30 years
.
 
In the future, we may be involved in
additional environmental assessments, cleanups
 
and proceedings.
 
Legal Proceedings
We are subject to various lawsuits and claims including but not limited to matters
 
involving oil and gas royalty
and severance tax payments, gas measurement and
 
valuation methods, contract disputes,
 
environmental
damages, climate change, personal injury, and property damage.
 
Our primary exposures for such matters
relate to alleged royalty and tax underpayments
 
on certain federal, state and privately owned
 
properties and
claims of alleged environmental contamination
 
from historic operations.
 
We will continue to defend ourselves
vigorously in these matters.
 
Our legal organization applies its knowledge, experience
 
and professional judgment to the specific
characteristics of our cases, employing a litigation
 
management process to manage and monitor the
 
legal
proceedings against us.
 
Our process facilitates the early evaluation and quantification
 
of potential exposures in
individual cases.
 
This process also enables us to track those cases that
 
have been scheduled for trial and/or
mediation.
 
Based on professional judgment and experience
 
in using these litigation management tools and
available information about current developments
 
in all our cases, our legal organization regularly assesses
 
the
adequacy of current accruals and determines if
 
adjustment of existing accruals, or establishment
 
of new
accruals, is required.
 
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and
 
processing companies
not associated with financing arrangements.
 
Under these agreements, we may be required
 
to provide any such
company with additional funds through advances
 
and penalties for fees related to throughput capacity
 
not
utilized.
 
In addition, at September 30, 2020, we had performance
 
obligations secured by letters of credit
 
of
 
$
240
 
million (issued as direct bank letters of
 
credit) related to various purchase commitments
 
for materials,
supplies, commercial activities and services incident
 
to the ordinary conduct of business.
 
 
In 2007, ConocoPhillips was unable to reach agreement
 
with respect to the empresa mixta structure
 
mandated
by the Venezuelan government’s Nationalization Decree.
 
As a result, Venezuela’s
 
national oil company,
Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’
interests in the Petrozuata and Hamaca heavy oil
 
ventures and the offshore Corocoro development project.
 
In
response to this expropriation, ConocoPhillips
 
initiated international arbitration on November 2, 2007,
 
with the
ICSID.
 
On September 3, 2013, an ICSID arbitration tribunal
 
held that Venezuela unlawfully expropriated
ConocoPhillips’ significant oil investments
 
in June 2007.
 
On January 17, 2017, the Tribunal reconfirmed the
decision that the expropriation was unlawful.
 
In March 2019, the Tribunal unanimously ordered the
government of Venezuela to pay ConocoPhillips approximately $
8.7
 
billion in compensation for the
government’s unlawful expropriation of the company’s investments in Venezuela in 2007.
 
ConocoPhillips has
filed a request for recognition of the award in several
 
jurisdictions.
 
On August 29, 2019, the ICSID Tribunal
issued a decision rectifying the award and reducing
 
it by approximately $
227
 
million.
 
The award now stands
at $
8.5
 
billion plus interest.
 
The government of Venezuela sought annulment of the award, which
automatically stayed enforcement of the award.
 
Annulment proceedings are underway.
 
 
15
 
In 2014, ConocoPhillips filed a separate and independent
 
arbitration under the rules of the ICC against
PDVSA under the contracts that had established the
 
Petrozuata and Hamaca projects.
 
The ICC Tribunal issued
an award in April 2018, finding that PDVSA owed ConocoPhillips
 
approximately $
2
 
billion under their
agreements in connection with the expropriation of the
 
projects and other pre-expropriation fiscal
 
measures.
 
In
August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC
award, plus interest through the payment period, including initial payments totaling approximately
$500 million within a period of 90 days from the time of signing of the settlement agreement. The balance of
the settlement is to be paid quarterly over a period of four and a half years.
 
To date, ConocoPhillips has
received approximately $
754
 
million.
 
Per the settlement, PDVSA recognized the ICC award
 
as a judgment in
various jurisdictions, and ConocoPhillips agreed
 
to suspend its legal enforcement actions.
 
ConocoPhillips sent
notices of default to PDVSA on October 14 and November
 
12, 2019, and to date PDVSA has failed to cure its
breach.
 
As a result, ConocoPhillips has resumed legal enforcement
 
actions.
 
ConocoPhillips has ensured that
the settlement and any actions taken in enforcement
 
thereof meet all appropriate U.S. regulatory
 
requirements,
including those related to any applicable sanctions
 
imposed by the U.S. against Venezuela.
 
In 2016, ConocoPhillips filed a separate and independent
 
arbitration under the rules of the ICC against
PDVSA under the contracts that had established the
 
Corocoro Project.
 
On August 2, 2019, the ICC Tribunal
awarded ConocoPhillips approximately $
33
 
million plus interest under the Corocoro contracts.
 
ConocoPhillips is seeking recognition and enforcement
 
of the award in various jurisdictions.
 
ConocoPhillips
has ensured that all the actions related to the award
 
meet all appropriate U.S. regulatory requirements,
including those related to any applicable sanctions
 
imposed by the U.S. against Venezuela.
 
The Office of Natural Resources Revenue (ONRR) has conducted
 
audits of ConocoPhillips’ payment of
royalties on federal lands and has issued multiple
 
orders to pay additional royalties to the federal
 
government.
 
ConocoPhillips has appealed these orders and strongly
 
objects to the ONRR claims.
 
The appeals are pending
with the Interior Board of Land Appeals (IBLA),
 
except for one order that is the subject of
 
a lawsuit
ConocoPhillips filed in 2016 in New Mexico federal
 
court after its appeal was denied by the
 
IBLA.
 
Beginning in 2017, cities, counties, governments
 
and other entities in several states in the U.S. have
 
filed
lawsuits against oil and gas companies, including
 
ConocoPhillips, seeking compensatory damages
 
and
equitable relief to abate alleged climate change impacts.
 
Additional lawsuits with similar allegations
 
are
expected to be filed.
 
The amounts claimed by plaintiffs are unspecified and
 
the legal and factual issues
involved in these cases are unprecedented.
 
ConocoPhillips believes these lawsuits are factually
 
and legally
meritless and are an inappropriate vehicle to address
 
the challenges associated with climate
 
change and will
vigorously defend against such lawsuits.
 
Several Louisiana parishes and the State of Louisiana
 
have filed
43
 
lawsuits under Louisiana’s State and Local
Coastal Resources Management Act (SLCRMA)
 
against oil and gas companies, including ConocoPhillips,
seeking compensatory damages for contamination
 
and erosion of the Louisiana coastline
 
allegedly caused by
historical oil and gas operations.
 
ConocoPhillips entities are defendants in
22
 
of the lawsuits and will
vigorously defend against them.
 
Because Plaintiffs’ SLCRMA theories are unprecedented,
 
there is uncertainty
about these claims (both as to scope and damages)
 
and any potential financial impact on the company.
 
In 2016, ConocoPhillips, through its subsidiary, The Louisiana Land and Exploration
 
Company LLC,
submitted claims as the largest private wetlands owner in Louisiana
 
within the settlement claims
administration process related to the oil spill
 
in the Gulf of Mexico in April 2010.
 
In July 2020, the claims
administrator issued an award to the company which,
 
after fees and expenses, totaled approximately
 
$
90
million,
 
which was received in the third quarter of 2020.
 
In October 2020, the Bureau of Safety and Environmental
 
Enforcement (BSEE) ordered the prior owners of
Outer Continental Shelf (OCS) Lease P-0166, including
 
ConocoPhillips, to decommission the lease facilities,
including two offshore platforms located near Carpinteria,
 
California.
 
This order was sent after the current
owner of OCS Lease P-0166 relinquished the lease
 
and abandoned the lease platforms and facilities.
 
Phillips
Petroleum Company, a legacy company of ConocoPhillips, held a
25
 
percent interest in this lease and operated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
16
these facilities, but sold its interest approximately
30 years
 
ago.
 
ConocoPhillips has not had any connection to
the operation or production on this lease since that
 
time.
 
ConocoPhillips plans to challenge the order.
 
 
Note 13—Derivative and Financial Instruments
 
We use futures, forwards, swaps and options in various markets to meet our customer needs,
 
capture market
opportunities and manage foreign exchange currency
 
risk.
 
 
Commodity Derivative Instruments
Our commodity business primarily consists
 
of natural gas, crude oil, bitumen, LNG and NGLs.
 
 
Commodity derivative instruments are held at fair
 
value on our consolidated balance sheet.
 
Where these
balances have the right of setoff, they are presented on a
 
net basis.
 
Related cash flows are recorded as
operating activities on our consolidated statement
 
of cash flows.
 
On our consolidated income statement,
realized and unrealized gains and losses are recognized
 
either on a gross basis if directly related to our
 
physical
business or a net basis if held for trading.
 
Gains and losses related to contracts that meet
 
and are designated
with the NPNS exception are recognized upon settlement.
 
We generally apply this exception to eligible crude
contracts.
 
We do not elect hedge accounting for our commodity derivatives.
 
The following table presents the gross fair values
 
of our commodity derivatives, excluding
 
collateral, and the
line items where they appear on our consolidated
 
balance sheet:
Millions of Dollars
September 30
December 31
2020
2019
Assets
Prepaid expenses and other current assets
$
273
288
Other assets
28
34
Liabilities
Other accruals
258
283
Other liabilities and deferred credits
19
28
 
 
The gains (losses) from commodity derivatives
 
incurred, and the line items where they appear on
 
our
consolidated income statement were:
Millions of Dollars
 
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Sales and other operating revenues
$
33
4
30
68
Other income (loss)
(2)
3
3
4
Purchased commodities
(27)
(9)
(29)
(60)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
17
The table below summarizes our material net exposures
 
resulting from outstanding commodity
 
derivative
contracts:
Open Position
Long/(Short)
September 30
December 31
2020
2019
Commodity
Natural gas and power (billions of cubic feet equivalent)
 
Fixed price
(9)
(5)
 
Basis
(50)
(23)
 
 
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.
 
Our foreign currency exchange derivative instruments
 
are held at fair value on our consolidated
 
balance sheet.
Related cash flows are recorded as operating activities
 
on our consolidated statement of cash flows.
 
We do not
elect hedge accounting on our foreign currency exchange
 
derivatives.
 
The following table presents the gross fair values
 
of our foreign currency exchange derivatives,
 
excluding
collateral, and the line items where they appear
 
on our consolidated balance sheet:
Millions of Dollars
September 30
December 31
2020
2019
Assets
Prepaid expenses and other current assets
$
16
1
Liabilities
Other accruals
-
20
Other liabilities and deferred credits
-
8
 
 
The (gains) losses from foreign currency exchange
 
derivatives incurred, and the line item where
 
they appear
on our consolidated income statement were:
Millions of Dollars
 
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Foreign currency transaction (gain) loss
$
7
(24)
(55)
(3)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18
We had the following net notional position of outstanding foreign currency exchange
 
derivatives:
In Millions
Notional Currency
September 30
December 31
2020
2019
Foreign Currency Exchange Derivatives
Buy GBP,
 
sell EUR
GBP
3
4
Sell CAD, buy USD
CAD
416
1,337
 
 
In the second quarter of 2019, we entered into foreign currency exchange contracts to sell CAD 1.35 billion at
CAD 0.748 against the USD. In the first quarter of 2020, we entered into forward currency exchange contracts
to buy CAD 0.9 billion at CAD 0.718 against the USD
.
 
 
 
Financial Instruments
We invest in financial instruments with maturities based on our cash forecasts for
 
the various accounts and
currency pools we manage.
 
The types of financial instruments in which we
 
currently invest include:
 
 
Time deposits: Interest bearing deposits placed with financial
 
institutions for a predetermined amount
of time.
 
 
Demand deposits: Interest bearing deposits placed
 
with financial institutions.
 
Deposited funds can be
withdrawn without notice.
 
Commercial paper: Unsecured promissory notes issued
 
by a corporation, commercial bank or
government agency purchased at a discount to
 
mature at par.
 
U.S. government or government agency obligations:
 
Securities issued by the U.S. government
 
or U.S.
government agencies.
 
Foreign government obligations: Securities
 
issued by foreign governments.
 
Corporate bonds: Unsecured debt securities
 
issued by corporations.
 
Asset-backed securities: Collateralized debt securities.
 
 
The following investments are carried on our
 
consolidated balance sheet at cost, plus accrued
 
interest:
 
Millions of Dollars
Carrying Amount
Cash and Cash
Equivalents
Short-Term
Investments
September 30
December 31
September 30
December 31
2020
2019
2020
2019
Cash
$
545
759
Demand Deposits
1,182
1,483
Time Deposits
Remaining maturities from 1 to 90 days
755
2,030
2,961
1,395
Remaining maturities from 91 to 180 days
-
-
741
465
Remaining maturities within one year
-
-
7
-
Commercial Paper
Remaining maturities from 1 to 90 days
-
413
50
1,069
U.S. Government Obligations
Remaining maturities from 1 to 90 days
5
394
-
-
$
2,487
5,079
3,759
2,929
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
19
The following investments in debt securities
 
classified as available for sale are carried on our
 
consolidated
balance sheet at fair value:
Millions of Dollars
Carrying Amount
Cash and Cash Equivalents
Short-Term
Investments
Investments and Long-Term
Receivables
September 30
2020
December 31
2019
September 30
2020
December 31
2019
September 30
2020
December 31
2019
Corporate Bonds
Maturities within one year
$
-
1
157
59
-
-
Maturities greater than one year
 
through five years
-
-
-
-
128
99
Commercial Paper
Maturities within one year
3
8
108
30
-
-
U.S. Government Obligations
Maturities within one year
-
-
8
10
-
-
Maturities greater than one year
 
through five years
-
-
-
-
13
15
U.S. Government Agency Obligations
Maturities greater than one year
 
through five years
-
-
-
-
17
-
Foreign Government Obligations
Maturities greater than one year
 
through five years
-
-
-
-
2
-
Asset-backed Securities
Maturities greater than one year
 
through five years
-
-
-
-
46
19
$
3
9
273
99
206
133
 
 
The following table summarizes the amortized
 
cost basis and fair value of investments in
 
debt securities
classified as available for sale:
Millions of Dollars
September 30, 2020
December 31, 2019
Amortized
Cost Basis
Fair Value
Amortized
Cost Basis
Fair Value
Major Security Type
Corporate bonds
$
283
285
159
159
Commercial paper
111
111
38
38
U.S. government obligations
21
21
25
25
U.S. government agency obligations
17
17
-
-
Foreign government obligations
2
2
-
-
Asset-backed securities
46
46
19
19
$
480
482
241
241
 
As of September 30, 2020 and December 31, 2019,
 
total unrealized losses for debt securities
 
classified as
available for sale with net losses were negligible.
 
Additionally, as of September 30, 2020 and December 31,
2019, investments
 
in these debt securities in an unrealized loss
 
position for which an allowance for credit
losses has not been recorded were negligible.
 
 
 
20
For the three-
 
and nine-month periods ended September 30,
 
2020, proceeds from sales and redemptions of
investments in debt securities classified as available
 
for sale were $
109
 
million and $
298
 
million, respectively.
 
Gross realized gains and losses included in earnings
 
from those sales and redemptions were negligible.
 
The
cost of securities sold and redeemed is determined
 
using the specific identification method.
 
 
Credit Risk
Financial instruments potentially exposed to concentrations
 
of credit risk consist primarily of cash equivalents,
short-term investments, long-term investments
 
in debt securities, OTC derivative contracts and trade
receivables.
 
Our cash equivalents and short-term investments
 
are placed in high-quality commercial paper,
government money market funds, government debt
 
securities, time deposits with major international
 
banks and
financial institutions, and high-quality corporate bonds.
 
Our long-term investments in debt securities
 
are
placed in high-quality corporate bonds, U.S. government
 
and government agency obligations, foreign
government obligations, and asset-backed securities.
 
 
The credit risk from our OTC derivative contracts,
 
such as forwards, swaps and options, derives
 
from the
counterparty to the transaction.
 
Individual counterparty exposure is managed
 
within predetermined credit
limits and includes the use of cash-call margins when appropriate,
 
thereby reducing the risk of significant
nonperformance.
 
We also use futures, swaps and option contracts that have a negligible credit
 
risk because
these trades are cleared 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.
 
Our collateral requirements will depend on the
 
creditworthiness of our
counterparties.
 
At our option, we may require collateral to limit
 
the exposure to loss including, letters of
credit, prepayments and surety bonds, as well as
 
master netting arrangements to mitigate
 
credit risk with
counterparties that both buy from and sell to
 
us, as these agreements permit the amounts
 
owed by us or owed
to others to be offset against amounts due to us.
 
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative
exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts
with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts
typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert
to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also
permit us to post letters of credit as collateral, such as transactions administered through the New York
Mercantile Exchange.
 
The aggregate fair value of all derivative
 
instruments with such credit risk-related contingent
 
features that were
in a liability position on September 30, 2020 and December
 
31, 2019, was $
20
 
million and $
79
 
million,
respectively.
 
For these instruments,
no
 
collateral was posted as of September 30, 2020
 
or December 31, 2019.
 
If our credit rating had been downgraded below
 
investment grade on September 30, 2020, we would
 
have been
required to post $
16
 
million of additional collateral, either with
 
cash or letters of credit.
 
21
Note 14—Fair Value Measurement
 
We carry a portion of our assets and liabilities at fair value measured at the reporting
 
date using an exit price
(i.e., the price that would be received to sell an asset
 
or paid to transfer a liability) and disclosed
 
according to
the quality of valuation inputs under the following
 
hierarchy:
 
 
Level 1: Quoted prices (unadjusted) in an active
 
market for identical assets or liabilities.
 
Level 2: Inputs other than quoted prices that
 
are directly or indirectly observable.
 
Level 3: Unobservable inputs that are significant
 
to the fair value of assets or liabilities.
 
The classification hierarchy 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.
 
There were no material transfers into or
 
out of Level 3 during
2020 or 2019.
 
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair
 
value on a recurring basis primarily include
 
our investment in
Cenovus Energy common shares, our investments in debt
 
securities classified as available for sale, and
commodity derivatives.
 
 
 
Level 1 derivative assets and liabilities primarily
 
represent exchange-traded futures and options that are
valued using unadjusted prices available from the
 
underlying exchange.
 
Level 1 also includes our
investment in common shares of Cenovus Energy, which is valued using quotes for shares
 
on the NYSE,
and our investments in U.S. government obligations
 
classified
 
as available for sale debt securities, which
are valued using exchange prices.
 
Level 2 derivative assets and liabilities primarily
 
represent OTC swaps, options and forward purchase
 
and
sale contracts that are valued using adjusted exchange
 
prices, prices provided by brokers or pricing
 
service
companies that are all corroborated by market data.
 
Level 2 also includes our investments in debt
securities classified as available for sale including
 
investments in corporate bonds, commercial
 
paper,
asset-backed securities, U.S. government agency
 
obligations and foreign government obligations
 
that are
valued using pricing provided by brokers or pricing
 
service companies that are corroborated with
 
market
data.
 
Level 3 derivative assets and liabilities consist
 
of OTC swaps, options and forward purchase and
 
sale
contracts where a significant portion of fair
 
value is calculated from underlying market
 
data that is not
readily available.
 
The derived value uses industry standard methodologies
 
that may consider the historical
relationships among various commodities, modeled
 
market prices, time value, volatility factors and other
relevant economic measures.
 
The use of these inputs results in management’s best estimate of fair
 
value.
 
Level 3 activity was not material for all periods
 
presented.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
22
The following table summarizes the fair value
 
hierarchy for gross financial assets and liabilities
 
(i.e.,
unadjusted where the right of setoff exists for commodity
 
derivatives accounted for at fair value on a recurring
basis):
 
Millions of Dollars
September 30, 2020
December 31, 2019
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investment in Cenovus Energy
$
809
-
-
809
2,111
-
-
2,111
Investments in debt securities
21
461
-
482
25
216
-
241
Commodity derivatives
173
117
11
301
172
114
36
322
Total assets
$
1,003
578
11
1,592
2,308
330
36
2,674
Liabilities
Commodity derivatives
$
173
89
15
277
174
115
22
311
Total liabilities
$
173
89
15
277
174
115
22
311
 
 
The following table summarizes those commodity
 
derivative balances subject to the right of setoff as
presented on our consolidated balance sheet.
 
We have elected to offset the recognized fair value amounts for
multiple derivative instruments executed with the
 
same counterparty in our financial statements
 
when a legal
right of setoff exists.
Millions of Dollars
Amounts Subject to Right of Setoff
Gross
Amounts Not
Gross
Net
Amounts
Subject to
Gross
Amounts
Amounts
Cash
Net
Recognized
Right of Setoff
Amounts
Offset
Presented
Collateral
Amounts
September 30, 2020
Assets
$
301
1
300
204
96
5
91
Liabilities
277
-
277
204
73
7
66
December 31, 2019
Assets
$
322
3
319
193
126
4
122
Liabilities
311
4
307
193
114
12
102
At September 30, 2020 and December 31, 2019,
 
we did not present any amounts gross on our consolidated
balance sheet where we had the right of setoff.
 
Non-Recurring Fair Value Measurement
The following table summarizes the fair value
 
hierarchy by major category and date of
 
remeasurement for
assets accounted for at fair value on a non-recurring
 
basis:
Millions of Dollars
Fair Value
Measurement
Using
Fair Value
Level 3 Inputs
Before-Tax
Loss
Net PP&E (held for use)
March 31, 2020
$
77
77
510
 
 
 
 
 
 
 
 
23
During the first quarter of 2020
, the estimated fair value of our assets in the Wind River Basin operations
 
area
declined to an amount below the carrying value.
 
The Wind River Basin operations area consists of certain
developed natural gas properties in the Madden
 
Field and the Lost Cabin Gas Plant and is included
 
in our
Lower 48 segment.
 
The carrying value was written down to fair value. The fair value was estimated based on
an internal discounted cash flow model using estimates of future production, an outlook of future prices using
a combination of exchanges (short-term) and external pricing services companies (long-term), future operating
costs and capital expenditures, and a discount rate believed to be consistent with those used by principal
market participants.
 
The range and arithmetic average of significant
 
unobservable inputs used in the Level 3
fair value measurement were as follows:
 
 
Fair Value
(Millions of
Dollars)
Valuation
Technique
Unobservable Inputs
Range
 
(Arithmetic Average)
March 31, 2020
Wind River Basin
$
77
Discounted cash
flow
Natural gas production
(MMCFD)
8.4
 
-
55.2
 
(
22.9
)
Natural gas price outlook*
($/MMBTU)
$
2.67
 
- $
9.17
 
($
5.68
)
Discount rate**
7.9
%
 
-
9.1
% (
8.3
%)
 
*Henry Hub natural gas price outlook based on external pricing service
 
companies' outlooks for years 2022-2034; future prices
 
escalated at
2.2
% annually after
year 2034.
**Determined as the weighted average cost of capital of a group
 
of peer companies, adjusted for risks where
 
appropriate.
 
Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial
 
instruments:
 
 
Cash and cash equivalents and short-term investments:
 
The carrying amount reported on the balance
sheet approximates fair value.
 
For those investments classified as available
 
for sale debt securities,
the carrying amount reported on the balance sheet
 
is fair value.
 
Accounts and notes receivable (including long-term
 
and related parties): The carrying amount
reported on the balance sheet approximates fair
 
value.
 
The valuation technique and methods used to
estimate the fair value of the current portion
 
of fixed-rate related party loans is consistent with
 
Loans
and advances—related parties.
 
Investment in Cenovus Energy: See Note 6—Investment in
 
Cenovus Energy for a discussion of the
carrying value and fair value of our investment in
 
Cenovus Energy common shares.
 
 
Investments in debt securities classified as available
 
for sale: The fair value of investments in debt
securities categorized as Level 1 in the fair
 
value hierarchy is measured using exchange
 
prices.
 
The
fair value of investments in debt securities
 
categorized as Level 2 in the fair value hierarchy
 
is
measured using pricing provided by brokers or pricing
 
service companies that are corroborated
 
with
market data.
 
See Note 13—Derivatives and Financial Instruments,
 
for additional information.
 
Loans and advances—related parties: The carrying
 
amount of floating-rate loans approximates
 
fair
value.
 
The fair value of fixed-rate loan activity is
 
measured using market observable data and is
categorized as Level 2 in the fair value hierarchy.
 
See Note 5—Investments, Loans and Long-Term
Receivables, for additional information.
 
Accounts payable (including related parties)
 
and floating-rate debt: The carrying amount of accounts
payable and floating-rate debt reported on the balance
 
sheet approximates fair value.
 
 
Fixed-rate debt: The estimated fair value of fixed-rate
 
debt is measured using prices available
 
from a
pricing service that is corroborated by market data;
 
therefore, these liabilities are categorized as Level
2 in the fair value hierarchy.
 
Commercial paper: The carrying amount of our
 
commercial paper instruments approximates
 
fair value
and is reported on the balance sheet as short-term
 
debt.
 
See Note 9—Debt, for additional information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24
The following table summarizes the net fair
 
value of financial instruments (i.e., adjusted
 
where the right of
setoff exists for commodity derivatives):
Millions of Dollars
Carrying Amount
Fair Value
September 30
December 31
September 30
December 31
2020
2019
2020
2019
Financial assets
Investment in Cenovus Energy
$
809
2,111
809
2,111
Commodity derivatives
92
125
92
125
Investments in debt securities
482
241
482
241
Total loans and advances—related parties
219
339
219
339
Financial liabilities
Total debt, excluding finance leases
14,482
14,175
18,827
18,108
Commodity derivatives
66
106
66
106
 
 
Note 15—Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss in the
 
equity section of our consolidated balance
 
sheet included:
Millions of Dollars
Defined
Benefit Plans
Net
Unrealized
Gain on
Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
December 31, 2019
$
(350)
-
(5,007)
(5,357)
Other comprehensive income (loss)
(13)
2
(298)
(309)
September 30, 2020
$
(363)
2
(5,305)
(5,666)
 
 
The following table summarizes reclassifications
 
out of accumulated other comprehensive loss and into
 
net
income (loss):
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Defined benefit plans
$
30
36
46
66
The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $
7
 
million and $
12
million for the three-month periods ended September 30, 2020 and September 30, 2019, respectively, and $
11
 
million and $
22
 
million for the
nine-month periods ended September 30, 2020 and September 30, 2019,
 
respectively.
 
See Note 17—Employee Benefit Plans, for additional
information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25
Note 16—Cash Flow Information
Millions of Dollars
Nine Months Ended
September 30
2020
2019
Cash Payments
Interest
$
591
614
Income taxes
803
2,210
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(9,662)
(1,894)
Short-term investments sold
8,776
1,229
Long-term investments purchased
(271)
-
Long-term investments sold
68
-
$
(1,089)
(665)
 
 
Note 17—Employee Benefit Plans
Pension and Postretirement Plans
Millions of Dollars
Pension Benefits
Other Benefits
2020
2019
2020
2019
U.S.
Int'l.
U.S.
Int'l.
Components of Net Periodic Benefit Cost
Three Months Ended September 30
Service cost
$
21
14
20
19
1
1
Interest cost
17
21
21
25
2
1
Expected return on plan assets
(21)
(37)
(18)
(34)
-
-
Amortization of prior service credit
-
(1)
-
-
(7)
(7)
Recognized net actuarial loss (gain)
12
5
13
7
1
(1)
Settlements
27
-
37
-
-
-
Curtailments
-
-
-
(1)
-
-
Net periodic benefit cost
$
56
2
73
16
(3)
(6)
Nine Months Ended September 30
Service cost
$
63
41
59
56
2
1
Interest cost
51
63
63
77
5
6
Expected return on plan assets
(63)
(108)
(54)
(104)
-
-
Amortization of prior service credit
-
(1)
-
(1)
(23)
(24)
Recognized net actuarial loss (gain)
37
16
39
23
1
(2)
Settlements
28
(1)
54
-
-
-
Curtailments
-
-
-
(1)
-
-
Net periodic benefit cost
$
116
10
161
50
(15)
(19)
 
The components of net periodic benefit cost, other
 
than the service cost component, are included in
 
the “Other
expenses” line item on our consolidated income statement.
 
During the first nine months of 2020, we contributed
 
$
87
 
million to our domestic benefit plans and $
57
 
million
to our international benefit plans.
 
In 2020, we expect to contribute a total of approximately
 
$
135
 
million to
our domestic qualified and nonqualified pension
 
and postretirement benefit plans and $
65
 
million to our
international qualified and nonqualified pension
 
and postretirement benefit plans.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
26
During the three-month period ended September
 
30, 2020, lump-sum benefit payments exceeded
 
the sum of
service and interest costs for the year for the U.S.
 
qualified pension plan.
 
As a result, we recognized a
proportionate share of prior actuarial losses from
 
other comprehensive income as pension settlement
 
expense
of $
27
 
million.
 
In conjunction with the recognition of pension
 
settlement expense, the fair market values of
the pension plan assets were updated and the pension
 
benefit obligation of the plan was
 
remeasured as of
September 30, 2020.
 
At the measurement date, the net pension liability
 
increased by $
78
 
million, resulting in a
corresponding decrease to other comprehensive loss.
 
This is primarily a result of a decrease in the discount
rate and reduced long-term lump sum rate assumptions
 
offset by better actual return on assets compared with
the expected return.
 
 
 
Note 18—Related Party Transactions
Our related parties primarily include equity method
 
investments and certain trusts for the benefit
 
of
employees.
 
For disclosures on trusts for the benefit
 
of employees, see Note 17—Employee Benefit
 
Plans.
Significant transactions with our equity affiliates were:
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Operating revenues and other income
$
21
23
59
70
Purchases
-
-
-
38
Operating expenses and selling, general and administrative
expenses
16
19
43
47
Net interest income*
(1)
(3)
(5)
(10)
*We paid interest to, or received interest
 
from, various affiliates.
 
See Note 5—Investments, Loans and Long-Term Receivables, for additional
information on loans to affiliated companies.
 
 
Note 19—Sales and Other Operating Revenues
 
Revenue from Contracts with Customers
 
The following table provides further disaggregation
 
of our consolidated sales and other operating
 
revenues:
 
 
Millions of Dollars
 
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Revenue from contracts with customers
$
3,078
6,240
9,908
19,932
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative
1,280
1,529
3,432
4,981
Financial derivative contracts
28
(13)
(47)
(54)
Consolidated sales and other operating revenues
$
4,386
7,756
13,293
24,859
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
27
Revenues from contracts outside the scope of ASC
 
Topic 606 relate primarily to physical gas contracts at
market prices which qualify as derivatives accounted
 
for under ASC Topic 815, “Derivatives and Hedging,”
and for which we have not elected NPNS.
 
There is no significant difference in contractual
 
terms or the policy
for recognition of revenue from these contracts
 
and those within the scope of ASC Topic 606.
 
The following
disaggregation of revenues is provided in conjunction
 
with Note 20—Segment Disclosures and Related
Information:
 
 
Millions of Dollars
 
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
$
1,018
1,099
2,692
3,823
Canada
152
86
452
427
Europe, Middle East and North Africa
110
344
288
731
Physical contracts meeting the definition of a derivative
$
1,280
1,529
3,432
4,981
 
 
Millions of Dollars
 
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
100
266
218
619
Natural gas
1,042
1,159
2,895
4,022
Other
138
104
319
340
Physical contracts meeting the definition of a derivative
$
1,280
1,529
3,432
4,981
 
 
Practical Expedients
Typically,
 
our commodity sales contracts are less than
 
12 months in duration; however, in certain specific
cases may extend longer, which may be out to the end of field
 
life.
 
We have long-term commodity sales
contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-
based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each
wholly unsatisfied performance obligation within the contract.
 
Accordingly,
we have applied the practical
expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price
allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially
unsatisfied) as of the end of the reporting period.
 
 
Receivables and Contract Liabilities
Receivables from Contracts with Customers
At September 30, 2020, the “Accounts and notes
 
receivable” line on our consolidated balance sheet,
 
includes
trade receivables of $
1,338
 
million compared with $
2,372
 
million at December 31, 2019, and includes both
contracts with customers within the scope of ASC
 
Topic 606 and those that are outside the scope of ASC
Topic 606.
 
We typically receive payment within 30 days or less (depending on the terms of the invoice) once
delivery is made.
 
Revenues that are outside the scope of ASC Topic 606 relate primarily to
 
physical gas sales
contracts at market prices for which we do not
 
elect NPNS and are therefore accounted for
 
as a derivative
under ASC Topic 815.
 
There is little distinction in the nature
 
of the customer or credit quality of trade
receivables associated with gas sold under contracts
 
for which NPNS has not been elected
 
compared to trade
receivables where NPNS has been elected.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
28
Contract Liabilities from Contracts with Customers
We have entered into contractual arrangements where we license proprietary technology
 
to customers related
to the optimization process for operating LNG
 
plants.
 
The agreements typically provide for negotiated
payments to be made at stated milestones.
 
The payments are not directly related to our performance under the
contract and are recorded as deferred revenue to be recognized as revenue when the customer can utilize and
benefit from their right to use the license.
 
Payments are received in installments over the construction period.
 
 
Millions of Dollars
Contract Liabilities
At December 31, 2019
$
80
Contractual payments received
8
At September 30, 2020
$
88
Amounts Recognized in the Consolidated Balance
 
Sheet at September 30, 2020
Current liabilities
$
47
Noncurrent liabilities
41
$
88
 
We expect to recognize the contract liabilities as of September 30, 2020, as revenue during 2021 and 2022.
 
There were
no
 
revenues recognized for the three- and nine-month
 
periods ended September 30, 2020.
 
 
Note 20—Segment Disclosures and Related Information
 
 
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a
 
worldwide
basis.
 
We manage our operations through
six
 
operating segments, which are primarily defined
 
by geographic
region: Alaska; Lower 48; Canada; Europe,
 
Middle East and North Africa; Asia Pacific
 
and Other
International.
 
 
Corporate and Other represents income and costs
 
not directly associated with an operating
 
segment, such as
most interest expense, 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.
 
Intersegment sales are at prices that approximate
 
market.
 
 
Effective with the third quarter of 2020, we have restructured
 
our segments to align with changes to our
internal organization.
 
The Middle East business was realigned from
 
the Asia Pacific and Middle East segment
to the Europe and North Africa segment.
 
The segments have been renamed the Asia Pacific
 
segment and the
Europe, Middle East and North Africa segment.
 
We have revised segment information disclosures and
segment performance metrics presented within
 
our results of operations for the current and prior
 
comparative
periods.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
29
Analysis of Results by Operating Segment
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Sales and Other Operating Revenues
Alaska
$
864
1,296
2,396
4,129
Intersegment eliminations
(30)
-
(11)
-
Alaska
834
1,296
2,385
4,129
Lower 48
2,323
3,728
6,859
11,690
Intersegment eliminations
(9)
(10)
(47)
(33)
Lower 48
2,314
3,718
6,812
11,657
Canada
348
633
1,026
2,173
Intersegment eliminations
(20)
(273)
(200)
(858)
Canada
328
360
826
1,315
Europe, Middle East and North Africa
432
1,225
1,320
4,084
Asia Pacific
477
1,085
1,930
3,458
Other International
1
-
5
-
Corporate and Other
-
72
15
216
Consolidated sales and other operating revenues
$
4,386
7,756
13,293
24,859
Sales and Other Operating Revenues by Geographic
 
Location
(1)
United States
$
3,148
5,085
9,209
15,996
Australia
-
412
605
1,282
Canada
328
360
826
1,315
China
161
191
374
593
Indonesia
167
223
503
654
Libya
6
288
50
809
Malaysia
148
258
447
928
Norway
358
632
1,046
1,781
United Kingdom
68
305
224
1,494
Other foreign countries
2
2
9
7
Worldwide consolidated
$
4,386
7,756
13,293
24,859
Sales and Other Operating Revenues by Product
Crude oil
$
2,321
4,612
6,981
14,006
Natural gas
1,509
1,799
4,354
6,717
Natural gas liquids
129
156
364
607
Other
(2)
427
1,189
1,594
3,529
Consolidated sales and other operating revenues by
 
product
$
4,386
7,756
13,293
24,859
(1) Sales and other operating revenues are attributable to countries based on the location of the selling operation.
(2) Includes LNG and bitumen.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
Alaska
$
(16)
306
(76)
1,152
Lower 48
(78)
26
(880)
425
Canada
(75)
51
(270)
273
Europe, Middle East and North Africa
92
2,171
318
3,050
Asia Pacific
25
443
945
1,220
Other International
(8)
73
14
285
Corporate and Other
(390)
(14)
(1,980)
64
Consolidated net income (loss) attributable
 
to ConocoPhillips
$
(450)
3,056
(1,929)
6,469
 
 
Millions of Dollars
September 30
December 31
2020
2019
Total Assets
Alaska
$
15,910
15,453
Lower 48
12,196
14,425
Canada
6,581
6,350
Europe, Middle East and North Africa
8,420
9,269
Asia Pacific
11,359
13,568
Other International
300
285
Corporate and Other
8,391
11,164
Consolidated total assets
$
63,157
70,514
 
 
Note 21—Income Taxes
 
Our effective tax rate was
12
 
percent in the three-month periods ended September
 
30, 2020 and 2019.
 
Both
periods were primarily impacted by shifts
 
in our before-tax income between higher and
 
lower tax jurisdictions
as well as the change in our U.S. valuation allowance
 
driven by the fair value measurement of our Cenovus
Energy common shares.
 
The three-month period ended September 30, 2019
 
was also impacted by the
recognition of certain tax incentives in Malaysia.
 
Our effective tax rates for the nine-month periods ended
 
September 30, 2020 and 2019 were
8
 
percent and
21
percent,
 
respectively.
 
The nine-month period ended September 30, 2020
 
was impacted by the same items
noted above.
 
Additionally, the nine-months ended September 30, 2020 was impacted by the
 
gain on
disposition recognized for our Australia-West assets of $
587
 
million with an associated tax benefit of $
10
million, the de-recognition of $
92
 
million of deferred tax assets recorded as income
 
tax expense as a result of
this divestiture, and a $
48
 
million refund from the Alberta Tax and Revenue Administration.
 
The nine-month
period ended September 30, 2019 was impacted
 
by the same items noted above in addition to
 
a benefit of $
262
million related to the recognition of a U.S. capital
 
loss benefit from our U.K. entity disposition.
 
As a result of the COVID-19 pandemic and the
 
resulting economic uncertainty, many countries in which we
operate, including Australia, Canada, Norway and
 
the U.S., have enacted responsive tax legislation.
 
During
the second quarter, Norway enacted legislation to accelerate
 
the recovery of capital expenditures and allow
immediate monetization of tax losses.
 
As a result, in the second quarter of 2020,
 
we recorded an increase to
our net deferred tax liability of $
120
 
million and a decrease to our accrued income
 
and other taxes liability of
$
124
 
million.
 
Legislation in other jurisdictions did not have
 
a material impact to ConocoPhillips.
 
 
 
31
During the three-
 
and nine-month periods ended September 30, 2020,
 
our valuation allowance increased by
$
33
 
million and $
264
 
million, respectively.
 
The change to our U.S. valuation allowance
 
for both periods
relates primarily to the fair value measurement of our
 
Cenovus Energy common shares and our expectation
 
of
the tax impact related to incremental capital
 
gains and losses.
 
 
 
Note 22—Announced Acquisition of Concho
 
Resources Inc.
 
 
On
October 19, 2020
, we announced a definitive agreement (the
 
Merger Agreement) to acquire
Concho
Resources Inc.
 
(Concho) in an all-stock transaction valued
 
at $
9.7
 
billion based upon closing share prices on
October 16, 2020.
 
Under the terms of the transaction,
 
which has been unanimously approved by the board
 
of
directors of each company, each share of Concho common stock will
 
be exchanged for a fixed ratio of
1.46
shares of ConocoPhillips common stock.
 
We will also assume the debt balances of Concho, which were
approximately $
3.9
 
billion at September 30, 2020.
 
 
The transaction is anticipated to close in the first
 
quarter of 2021, subject to the approval
 
of both
ConocoPhillips and Concho shareholders,
 
regulatory clearance, and other customary
 
closing conditions.
 
If the
Merger Agreement is terminated under certain circumstances,
 
we may be required to pay a termination fee of
$
450
 
million, including if the proposed Merger is terminated
 
because our board of directors has changed its
recommendation in respect of the stockholder
 
proposal relating to the Merger.
 
In addition, we may be required
to reimburse Concho for its expenses in an amount
 
equal to $
142.5
 
million if the Merger Agreement is
terminated because of a failure of our stockholders
 
to approve the stockholder proposal.
 
See Item 1A. “Risk
Factors” for further discussion of risks related
 
to the Concho acquisition.
 
32
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
 
Management’s
 
Discussion and Analysis is the company’s analysis of its financial performance and of
significant trends that may affect future performance.
 
It should be read in conjunction with the financial
statements and notes.
 
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 57.
 
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
 
 
BUSINESS ENVIRONMENT AND EXECUTIVE
 
OVERVIEW
 
ConocoPhillips is an independent E&P company
 
with operations and activities in 15 countries.
 
Our diverse,
low cost of supply portfolio includes resource-rich
 
unconventional plays in North America;
 
conventional
assets in North America, Europe and Asia; LNG
 
developments; oil sands assets in Canada;
 
and an inventory of
global conventional and unconventional exploration
 
prospects.
 
At September 30, 2020, we employed
approximately 9,800 people worldwide and had
 
total assets of $63 billion.
 
 
Announced Acquisition of Concho Resources Inc.
 
and Paris-Aligned
 
Climate Risk Strategy
 
On October 19, 2020, we announced entry into
 
a definitive agreement to acquire Concho
 
Resources Inc.
(Concho) in an all-stock transaction valued at $9.7
 
billion based upon closing share prices
 
on October 16,
2020.
 
Under the terms of the transaction, each outstanding
 
share of common stock of Concho will
 
be
converted into the right to receive 1.46 shares of ConocoPhillips
 
common stock.
 
We will also assume the debt
balances of Concho, which were approximately $3.9
 
billion at September 30, 2020.
 
The combined companies
are expected to capture $500 million of annual
 
cost and capital savings by 2022, which
 
would be sourced from
lower general and administrative costs and a reduction
 
in our future global new ventures exploration
 
program.
 
The transaction is anticipated to close in the first
 
quarter of 2021, subject to the approval
 
of both
ConocoPhillips and Concho shareholders, regulatory
 
clearance, and the satisfaction or waiver of
 
other
customary closing conditions.
 
See Item 1A. “Risk Factors” for further
 
discussion of risks related to the
Concho acquisition.
 
We also announced the adoption of a Paris-aligned climate risk framework as part of
 
our continued
commitment to ESG excellence.
 
This comprehensive climate risk strategy
 
should enable us to sustainably
meet global energy demand while delivering competitive
 
returns through the energy transition.
 
We have set a
target to reduce our gross operated (scope 1 and 2) emissions
 
intensity by 35 to 45 percent from 2016 levels
 
by
2030, with an ambition to achieve net zero by
 
2050 for operated emissions.
 
We are advocating for reduction
of scope 3 end-use emissions intensity through
 
our support for a U.S. carbon price and reaffirmed
 
our
commitment to the Climate Leadership Council.
 
We have joined the World
 
Bank Flaring Initiative to work
towards zero routine flaring of gas by 2030.
 
We are committed to take ESG leadership to the next level as the
first U.S.-based oil and gas company to adopt a Paris-aligned
 
climate risk strategy.
 
 
 
33
Overview
 
The energy landscape changed dramatically in 2020 with
 
simultaneous demand and supply shocks that drove
the industry into a severe downturn.
 
The demand shock was triggered by COVID-19,
 
which was declared a
global pandemic and caused unprecedented social
 
and economic consequences.
 
Mitigation efforts to stop the
spread of this contagious disease included stay-at-home
 
orders and business closures that caused sharp
contractions in economic activity worldwide.
 
The supply shock was triggered by disagreements
 
between
OPEC and Russia, beginning in early March, which
 
resulted in significant supply coming onto the market
 
and
an oil price war.
 
These dual demand and supply shocks caused
 
oil prices to collapse as we exited the first
quarter.
 
As we entered the second quarter, predictions of COVID-19 driven global
 
oil demand losses intensified, with
forecasts of unprecedented demand declines.
 
Based on these forecasts, OPEC plus nations held
 
an emergency
meeting, and in April they announced a coordinated
 
production cut that was unprecedented in both its
magnitude and duration.
 
The OPEC plus agreement spans from May 2020
 
until April 2022, with the volume
of production cuts easing over time.
 
Additionally, non-OPEC plus countries, including the U.S., Canada,
Brazil and other G-20 countries, announced organic reductions
 
to production through the release of drilling
rigs, frac crews, normal field decline and curtailments.
 
Despite these planned production decreases, the
 
supply
cuts were not timely enough to overcome significant
 
demand decline.
 
Futures prices for April WTI closed
under $20 a barrel for the first time since
 
2001, followed by May WTI settling below zero
 
on the day before
futures contracts expiry, as holders of May futures contracts struggled to
 
exit positions and avoid taking
physical delivery.
 
As storage constraints approached, spot prices in
 
April for certain North American
landlocked grades of crude oil were in the single digits
 
or even negative for particularly remote or low-grade
crudes, while waterborne priced crudes such as Brent
 
sold at a relative advantage.
 
The extreme volatility
experienced in the first half of the year settled down
 
in the third quarter, with crude oil prices stabilizing
 
around $40 per barrel.
 
 
Since the start of the severe downturn, we have closely
 
monitored the market and taken prudent actions in
response to this situation.
 
We entered the year in a position of relative strength, with cash and cash equivalents
of more than $5 billion, short-term investments
 
of $3 billion, and an undrawn credit facility
 
of $6 billion,
totaling approximately $14 billion in available
 
liquidity.
 
Additionally, we had several entity and asset sales
agreements in place, which generated $1.3 billion
 
in proceeds from dispositions during the first
 
nine-months of
2020.
 
For more information about the sales of our Australia-West and non-core Lower 48 assets,
 
see Note 4—
Asset Acquisitions and Dispositions in the
 
Notes to Consolidated Financial Statements.
 
This relative
advantage allowed us to be measured in our response
 
to the sudden change in business environment.
 
 
In March, we announced an initial set of actions
 
to address the downturn and followed up with additional
actions in April.
 
The combined announcements reflected a reduction
 
in our 2020 operating plan capital of $2.3
billion, a reduction to our operating costs of
 
$600 million and suspension of our share repurchase
 
program.
 
These actions will decrease uses of cash by approximately
 
$5 billion in 2020.
 
We also established a
framework for evaluating and implementing economic
 
production curtailments considering the weakness in
 
oil
prices during the second quarter of 2020, which resulted
 
in taking an additional significant step of voluntarily
curtailing production, predominantly from
 
operated North American assets.
 
Due to our strong balance sheet,
we were in an advantaged position to forgo some production
 
and cash flow in anticipation of receiving higher
cash flows for those volumes in the future.
 
In the second quarter, we curtailed production by an estimated 225 MBOED,
 
with 145 MBOED of the
curtailments from the Lower 48, 40 MBOED from
 
Alaska and 30 MBOED from our Surmont operation
 
in
Canada.
 
The remainder of the second-quarter curtailments
 
were primarily in Malaysia.
 
Other industry
operators also cut production and development plans
 
and as we progressed through the second quarter, stay-at-
home restrictions eased, which partially restored
 
lost demand, and WTI and Brent prices exited the
 
second
quarter around $40 per barrel.
 
Based on our economic criteria, we began restoring
 
production from voluntary
curtailments in July, and with oil stabilizing around $40 per barrel, we ended
 
our curtailment program during
the third quarter.
 
Curtailments in the third quarter averaged approximately
 
90 MBOED, with 65 MBOED
attributable to the Lower 48 and 15 MBOED to
 
Surmont.
 
34
 
In August 2020, we completed the agreement
 
to acquire additional Montney acreage for cash
 
consideration of
approximately $382 million,
 
subject to customary post-closing adjustments.
 
As part of the agreement, we
assumed approximately $31 million in financing
 
obligations for associated partially owned infrastructure.
 
This
acquisition consisted primarily of undeveloped properties
 
and included
 
140,000 net acres in the liquids-rich
Inga Fireweed asset Montney zone, which is
 
directly adjacent to our existing Montney position.
 
We now have
a Montney acreage position of 295,000 net acres
 
with a 100 percent working interest.
 
 
On September 30, 2020, we announced our intent
 
to resume share repurchases; however, we recently
announced the pending acquisition of Concho and
 
our suspension of share repurchases until
 
after the
transaction closes.
 
We ended the third quarter with over $12 billion of liquidity, comprised of $2.5 billion in
cash and cash equivalents, $4.0 billion in short-term
 
investments, and available borrowings under our credit
facility of $5.7 billion.
 
On October 9, 2020, we announced an increase
 
to our quarterly dividend from 42 cents
per share to 43 cents per share.
 
The dividend is payable on December 1, 2020
 
to shareholders of record as of
October 19, 2020.
 
 
Our expectation is that commodity prices will
 
remain cyclical and volatile, and a successful
 
business strategy
in the E&P industry must be resilient in
 
lower price environments, at the same time retaining
 
upside during
periods of higher prices.
 
While we are not impervious to current market
 
conditions, our decisive actions over
the last several years of focusing on free cash flow generation,
 
high-grading our asset base, lowering the cost
of supply of our investment resource portfolio,
 
and strengthening our balance sheet have
 
put us in a strong
relative position compared to our independent E&P
 
peers.
 
Although recent prices have been volatile, we
remain committed to our core value proposition
 
principles, namely, to focus on financial returns, maintain a
strong balance sheet, deliver compelling returns
 
of capital, and maintain disciplined capital
 
investments.
 
 
Our workforce and operations have adjusted to
 
mitigate the impacts of the COVID-19 global
 
pandemic.
 
We
have operations in remote areas with confined spaces,
 
such as offshore platforms, the North Slope of Alaska,
Curtis Island in Australia, western Canada and
 
Indonesia, where viruses could rapidly spread.
 
Personnel are
asked to perform a self-assessment for symptoms
 
of illness each day and, when appropriate,
 
are subject to
more restrictive measures traveling to and working
 
on location.
 
Staffing levels in certain operating locations
have been reduced to minimize health risk exposure
 
and increase social distancing.
 
A portion of our office
staff have continued to work successfully remotely, with offices around the world carefully
 
designing and
executing a flexible, phased reentry, following national, state and local guidelines.
 
These mitigation measures
have thus far been effective at reducing business operation
 
disruptions.
 
Workforce health and safety remains
the overriding driver for our actions and we have
 
demonstrated our ability to adapt to local
 
conditions as
warranted.
 
 
The marketing and supply chain side of our business
 
has also adapted in response to COVID-19.
 
Our
commercial organization managed transportation commitments
 
during our voluntary curtailment program.
 
Our supply chain function is proactively working
 
with vendors to ensure the continuity of our business
operations, monitor distressed service and materials
 
providers, capture deflation opportunities, and pursue
 
cost
reduction efforts.
 
 
Operationally, we remain focused on safely executing the business.
 
In the third quarter of 2020, production
 
of
1,067 MBOED generated cash provided by operating
 
activities of $0.9 billion.
 
We invested $1.1 billion into
the business in the form of capital expenditures, including
 
$0.4 billion of acquisition capital, and paid
dividends to shareholders of $0.5 billion.
 
Production decreased 299 MBOED or 22 percent
 
in the third quarter
of 2020, compared to the third quarter of 2019.
 
Adjusting for estimated curtailments of approximately
 
90
MBOED, closed acquisitions and dispositions
 
and Libya, third quarter 2020 production
 
would have been 1,155
MBOED, a decrease of 46 MBOED or 4 percent
 
compared with the third quarter of 2019.
 
This decrease was
primarily due to normal field decline, partly offset by new
 
wells online in the Lower 48, Canada and China.
 
Production from Libya averaged 1 MBOED as it
 
remained in force majeure during the third
 
quarter.
 
Force
majeure was lifted in October and plans to resume
 
production and exports are ongoing.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COP20203q10qp37i0.gif
 
COP20203q10qp37i1.gif
 
 
35
 
-
 
1
 
2
 
3
 
4
 
20
 
40
 
60
 
80
Q3'18
Q4'18
Q1'19
Q2'19
Q3'19
Q4'19
Q1'20
Q2'20
Q3'20
WTI/Brent
$/Bbl
WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Prices
Quarterly Averages
WTI - $/Bbl
Brent - $/Bbl
HH - $/MMBTU
HH
Business Environment
 
Commodity prices are the most significant
 
factor impacting our profitability and related reinvestment
 
of
operating cash flows into our business.
 
Among other dynamics that could influence world
 
energy markets and
commodity prices are global economic health, supply
 
or demand disruptions or fears thereof caused
 
by civil
unrest, global pandemics, military conflicts,
 
actions taken by OPEC plus and other major
 
oil producing
countries, environmental laws, tax regulations,
 
governmental policies and weather-related
 
disruptions.
 
Our
strategy is to create value through price cycles
 
by delivering on the financial and operational
 
priorities that
underpin our value proposition.
 
 
Our earnings and operating cash flows generally
 
correlate with price levels for crude oil
 
and natural gas, which
are subject to factors external to the company and over
 
which we have no control.
 
The following graph depicts
the trend in average benchmark prices for WTI
 
crude oil, Brent crude oil and Henry Hub natural
 
gas:
 
 
 
Brent crude oil prices averaged $43.00 per barrel
 
in the third quarter of 2020,
 
a decrease of 31 percent
compared with $61.94 per barrel in the third
 
quarter of 2019.
 
WTI at Cushing crude oil prices averaged
$40.93 per barrel in the third quarter of 2020,
 
a decrease of 27 percent compared with
 
$56.44 per barrel in the
third quarter of 2019.
 
Oil prices are lower due to high inventory levels
 
and contractions in economic activity
due to COVID-19 restrictions.
 
 
Henry Hub natural gas prices averaged $1.98
 
per MMBTU in the third quarter of 2020,
 
a decrease of 11
percent compared with $2.23 per MMBTU in the third
 
quarter of 2019.
 
Current period Henry Hub prices are
depressed due to high storage levels and seasonally
 
weak demand.
 
 
Our realized bitumen price averaged $15.87 per barrel
 
in the third quarter of 2020, a decrease of 51
 
percent
compared with $32.54 per barrel in the third
 
quarter of 2019.
 
The decrease in the third quarter of 2020 was
driven by a lower blend price for Surmont sales, largely attributed
 
to a weaker WTI price and a narrower
spread between the local market and U.S. sales
 
points, which challenged both pipeline and rail
 
economics.
 
In
addition, we incurred unutilized transportation
 
costs which negatively impacted our realized
 
bitumen price.
 
Our total average realized price was $30.94 per
 
BOE in the third quarter of 2020, compared with
 
$47.07 per
BOE in the third quarter of 2019.
 
 
 
 
36
Key Operating and Financial Summary
 
Significant items during the third quarter of 2020
 
and recent announcements included the following:
 
 
 
Produced 1,066 MBOED excluding Libya in the third
 
quarter;
 
curtailed approximately 90 MBOED.
 
Distributed $0.5 billion in dividends and announced
 
an increase to the quarterly dividend.
 
Ended the quarter with cash, cash equivalents and
 
restricted cash totaling $2.8
 
billion and short-term
investments of $4.0 billion.
 
 
As part of a commitment to ESG excellence, announced
 
adoption of a Paris-aligned climate risk
framework to achieve net zero
 
operated emissions by 2050.
 
Completed bolt-on acquisition of adjacent acreage
 
in the liquids-rich Montney in Canada for $0.4
billion.
 
Announced agreement to acquire Concho in an
 
all-stock transaction for 1.46 shares of ConocoPhillips
common stock per share of Concho.
 
 
Outlook
 
Capital and Production
 
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
In response to the
oil market downturn earlier this year, we announced capital
 
expenditure reductions totaling $2.3 billion.
 
Full
year 2020 operating plan capital is now expected
 
to be $4.3 billion.
 
This does not include approximately $0.5
billion of capital for acquisitions completed during
 
the year, of which $0.4 billion was for bolt-on acreage in
the liquids rich area of the Montney.
 
Fourth quarter 2020 production is expected to
 
be 1,125 to 1,165 MBOED, resulting in anticipated
 
full-year
2020 production of 1,115 to 1,125 MBOED.
 
This outlook excludes Libya.
 
 
Depreciation, Depletion and Amortization
DD&A expense was $4.0 billion in the nine-month
 
period of 2020.
 
Proved reserves estimates were updated
 
in
the interim periods of 2020 utilizing trailing
 
twelve-month oil and gas prices, which increased DD&A
 
expense
in the nine-month period of 2020 by approximately
 
$195 million before-tax.
 
If oil and gas prices persist at
depressed levels, our reserve estimates may
 
decrease further, which could incrementally increase the rate used
to determine DD&A expense on our unit-of-production
 
method properties.
 
 
Impairments
 
In October 2020, we announced an agreement to acquire
 
Concho, thereby significantly expanding our
unconventional acreage position in the Permian Basin.
 
The planned addition of unproved properties
 
in the
Delaware and Midland Basins would reduce our
 
need for resource additions through organic exploration,
 
and
we expect to decrease capital allocated to our global
 
new ventures exploration program going forward.
 
An
evaluation of our exploration program is ongoing
 
and may result in future impairments.
 
This transaction is
anticipated to close in the first
 
quarter of 2021, subject to the approval of both ConocoPhillips
 
and Concho
shareholders, regulatory clearance, and other customary
 
closing conditions.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
37
RESULTS OF OPERATIONS
 
 
Unless otherwise indicated, discussion of results for the three-
 
and nine-month periods ended September 30,
2020, is based on a comparison with the corresponding periods
 
of 2019.
 
Effective with the third quarter of 2020, we have restructured our segments to align with
 
changes to our
internal organization.
 
The Middle East business was realigned from the Asia Pacific and Middle East
 
segment
to the Europe and North Africa segment.
 
The segments have been renamed the Asia Pacific segment
 
and the
Europe, Middle East and North Africa segment.
 
We have revised segment information disclosures and
segment performance metrics presented within our results of operations for the
 
current and prior comparative
periods.
 
Consolidated Results
 
A summary of the company's net income (loss)
 
attributable to ConocoPhillips by business segment
 
follows:
 
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Alaska
$
(16)
306
(76)
1,152
Lower 48
(78)
26
(880)
425
Canada
(75)
51
(270)
273
Europe, Middle East and North Africa
92
2,171
318
3,050
Asia Pacific
25
443
945
1,220
Other International
(8)
73
14
285
Corporate and Other
(390)
(14)
(1,980)
64
Net income (loss) attributable to ConocoPhillips
$
(450)
3,056
(1,929)
6,469
 
 
Net income (loss) attributable to ConocoPhillips
 
in the third quarter of 2020 decreased $3,506 million.
 
Earnings were negatively impacted by:
 
 
The absence of a $1.8 billion after-tax gain associated
 
with the completion of the sale of two
ConocoPhillips U.K. subsidiaries.
 
Lower realized commodity prices.
 
Lower sales volumes, primarily due to normal field
 
decline, production curtailments across our
 
North
American operated assets and the divestiture of our
 
U.K. assets in the third quarter of 2019 and
Australia-West assets in the second quarter of 2020.
 
A $162 million after-tax unrealized loss on our Cenovus
 
Energy (CVE) common shares in the third
quarter of 2020, as compared to a $116 million after-tax gain
 
on those shares in the third quarter of
2019.
 
 
Lower equity in earnings of affiliates, primarily due to
 
lower LNG sales prices.
 
The absence of a $164 million income tax benefit
 
related to deepwater incentive tax credits
 
recognized
for Malaysia Block G.
 
 
 
 
38
Third quarter 2020 net income decreases were partly
 
offset by:
 
 
Lower production and operating expenses, primarily
 
due to the absence of costs related to our U.K.
and Australia-West divestitures and decreased wellwork and transportation costs
 
resulting from
production curtailments across our North American
 
operated assets.
 
Lower exploration expenses, primarily
 
due to the absence of $186 million after-tax of leasehold
impairment and dry hole costs associated with
 
our decision to discontinue exploration
 
activities in the
Central Louisiana Austin Chalk trend.
 
 
Lower DD&A, primarily due to lower volumes resulting
 
from production curtailments and our
 
Australia-West divestiture, partly offset by higher DD&A rates due to price-related downward reserve
revisions.
 
 
Net income (loss) attributable to ConocoPhillips
 
in the nine-month period ended September 30, 2020,
decreased $8,398 million.
 
Earnings were negatively impacted by:
 
 
Lower realized commodity prices.
 
Lower sales volumes, primarily due to normal field
 
decline, production curtailments across our
 
North
American operated assets and the divestiture of
 
our U.K. assets in the third quarter of 2019
 
and our
Australia-West assets in the second quarter of 2020.
 
The absence of a $2.1
 
billion after-tax gain associated with the completion
 
of the sale of two
ConocoPhillips U.K. subsidiaries.
 
 
A $1.3 billion after-tax unrealized loss on our CVE
 
common shares in the nine-month period of 2020,
as compared to a $0.5 billion after-tax gain on those
 
shares in the nine-month period of 2019.
 
 
Higher impairments of approximately $400 million
 
after-tax, primarily related to non-core gas assets
in our Lower 48 segment.
 
The absence of other income of $317 million after-tax
 
related to our settlement agreement with
PDVSA.
 
Lower equity in earnings of affiliates, primarily due to
 
lower LNG sales prices, partly offset by the
absence of $120 million after-tax of impairments
 
to equity method investments.
 
The decreases in earnings in the nine-month period
 
ended September 30, 2020,
 
were partly offset by:
 
 
A $597 million after-tax gain on dispositions related
 
to our Australia-West divestiture.
 
 
Lower production and operating expenses, primarily
 
due to decreased wellwork and transportation
costs resulting from production curtailments across
 
our North American operated assets as well
 
as the
absence of costs related to our U.K. and Australia-West divestitures.
 
Lower DD&A expenses, primarily due to lower volumes
 
related to production curtailments and our
Australia-West and U.K. divestitures, partly offset by higher DD&A rates due to price-related
downward reserve revisions.
 
Lower exploration expenses, primarily due
 
to the absence of $194 million after-tax of leasehold
impairment and dry hole costs associated with
 
our decision to discontinue exploration
 
activities in the
Central Louisiana Austin Chalk trend.
 
 
See the “Segment Results” section for additional
 
information.
 
 
 
 
 
 
 
 
 
 
 
39
Income Statement Analysis
 
 
 
Sales and other operating revenues for the three-
 
and nine-month periods of 2020 decreased
 
$3,370 million and
$11,566 million,
 
respectively, mainly due to lower realized commodity prices and lower sales
 
volumes.
 
Sales
volumes decreased due to normal field decline,
 
production curtailments from our North American
 
operated
assets and the divestiture of our U.K. assets in
 
the third quarter of 2019 and our Australia-West assets in the
second quarter of 2020.
 
 
Equity in earnings of affiliates for the three-
 
and nine-month periods of 2020 decreased
 
$255 million and $305
million,
 
respectively, primarily due to lower earnings from QG3 and APLNG as a result
 
of lower LNG sales
prices.
 
Partly offsetting this decrease was the absence of impairments
 
related to equity method investments in
our Lower 48 segment of $155 million in the
 
nine-month period of 2019.
 
 
Gain on dispositions for the three-
 
and nine-month periods of 2020 decreased $1,788
 
million and $1,333
million,
 
respectively, primarily due to the absence of a $1.8 billion before-tax gain associated
 
with the
completion of the sale of two ConocoPhillips
 
U.K. subsidiaries.
 
Partly offsetting the decrease in the nine-
month period of 2020, was a $587 million before-tax
 
gain associated with our Australia-West divestiture.
 
For
more information related to our Australia-West divestiture,
 
see Note 4—Asset Acquisitions and Dispositions
in the Notes to Consolidated Financial Statements.
 
Other income (loss) for the third quarter of 2020
 
decreased $300 million, primarily
 
due to an unrealized loss of
$162 million before-tax on our CVE common shares
 
in the third quarter of 2020, and the absence
 
of a $116
million before-tax gain on those shares in the third
 
quarter of 2019.
 
Other income (loss) for the nine-month
period of 2020 decreased $2,119 million,
 
primarily due to an unrealized loss of $1,302
 
million before-tax on
our CVE common shares in the nine-month period
 
of 2020, and the absence of a $489 million
 
before-tax gain
on those shares in the nine-month period of 2019.
 
Additionally, other income (loss) in the nine-month period
of 2020 decreased due to the absence of $325 million
 
before-tax related to our settlement agreement with
PDVSA.
 
For discussion of our Cenovus Energy shares, see Note
 
6—Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements.
 
For discussion of our PDVSA settlement, see Note
 
12—Contingencies
and Commitments, in the Notes to Consolidated Financial
 
Statements.
 
 
Purchased commodities for the three- and nine-month
 
periods
 
of 2020 decreased $871 million and $3,429
million,
 
respectively, primarily due to lower natural gas and crude oil prices and lower
 
crude oil and natural
gas volumes purchased.
 
 
Production and operating expenses for the three-
 
and nine-month periods of 2020 decreased
 
$368 million and
$837 million,
 
respectively, primarily due to decreased wellwork and transportation costs
 
associated with
production curtailments across our North American
 
operated assets as well as the absence of costs
 
related to
our U.K. and Australia-West divestitures.
 
Additionally, in the nine-month period of 2020, production and
operating expenses decreased due to lower legal
 
accruals in our Lower 48 and Other International
 
segments.
 
 
Selling, general and administrative expenses decreased
 
$120 million in the nine-month period of 2020,
primarily due to lower costs associated with compensation
 
and benefits, including mark to market impacts
 
of
certain key employee compensation programs.
 
Exploration expenses for the three- and nine-month
 
periods of 2020 decreased $235 million
 
and $182 million,
respectively, primarily due to the absence of a $141 million before-tax leasehold
 
impairment expense due to
our decision to discontinue exploration activities
 
in the Central Louisiana Austin Chalk trend and lower
 
dry
hole costs in the Lower 48, primarily
 
related to this play; partly offset by higher dry hole expenses in
 
Alaska.
 
In addition to the items detailed above, in the nine-month
 
period of 2020, the decrease in exploration expenses
were partly offset by an unproved property impairment
 
and dry hole expenses related to the Kamunsu East
Field in Malaysia that is no longer in our development
 
plans and charges related to the early termination of the
Alaska winter exploration program.
 
 
 
 
 
 
40
 
DD&A for the three-
 
and nine-month periods of 2020 decreased
 
$155 million and $622 million, respectively,
mainly due to lower production volumes because of
 
production curtailments and the divestiture
 
of our
Australia-West asset, partly offset by higher DD&A rates due to price-related downward
 
reserve revisions.
 
In
addition to the items detailed above, DD&A in the
 
nine-month period of 2020 decreased due to our
 
U.K.
divestiture, which met held-for-sale status in the
 
second quarter of 2019.
 
For more information regarding the
Australia-West divestiture, see Note 4—Asset Acquisitions and Dispositions in the Notes
 
to Consolidated
Financial Statements.
 
Impairments increased $495 million in
 
the nine-month period of 2020, primarily due to
 
a $511 million before-
tax impairment of certain non-core gas assets in
 
our Lower 48 segment because of a significant
 
decrease in the
outlook for natural gas prices.
 
See Note 8—Impairments in the Notes to Consolidated
 
Financial Statements,
for additional information.
 
Taxes other than income taxes for the three-
 
and nine-month periods of 2020 decreased
 
$58 million and $136
million, respectively, primarily due to lower commodity prices and sales volumes.
 
Foreign currency
 
transaction (gain) loss decreased $107 million
 
in the nine-month period of 2020,
 
resulting
from gains recognized from foreign currency derivatives
 
and other foreign currency remeasurements.
 
See
Note 13—Derivative and Financial Instruments
 
in the Notes to Consolidated Financial Statements,
 
for
additional information.
 
 
See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements,
 
for information regarding our
income tax provision (benefit) and effective tax rate.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
41
Summary Operating Statistics
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Average Net Production
Crude oil (MBD)
Consolidated operations
535
696
546
696
Equity affiliates
13
14
13
13
Total crude oil
548
710
559
709
Natural gas liquids (MBD)
Consolidated operations
89
106
97
106
Equity affiliates
8
8
7
8
Total natural gas liquids
97
114
104
114
Bitumen (MBD)
49
63
50
59
Natural gas (MMCFD)
Consolidated operations
1,201
1,795
1,353
1,783
Equity affiliates
1,034
1,076
1,042
1,043
Total natural gas*
2,235
2,871
2,395
2,826
Total Production
(MBOED)
1,067
1,366
1,112
1,353
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated operations
$
39.49
59.56
39.04
61.26
Equity affiliates
37.56
59.91
38.22
61.23
Total crude oil
39.45
59.57
39.02
61.26
Natural gas liquids (per bbl)
Consolidated operations
13.73
14.33
11.72
18.90
Equity affiliates
30.21
30.18
31.65
36.49
Total natural gas liquids
15.29
15.59
13.45
20.24
Bitumen (per bbl)
15.87
32.54
2.90
34.11
Natural gas (per MCF)
Consolidated operations
2.77
3.73
3.07
4.37
Equity affiliates
2.61
6.40
3.98
6.48
Total natural gas
2.70
4.74
3.47
5.17
Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical,
lease rental, and other
$
81
67
296
231
Leasehold impairment
-
154
31
196
Dry holes
44
139
83
165
$
125
360
410
592
*Represents quantities available for sale and excludes gas equivalent of natural gas
 
liquids included above.
 
42
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a
 
worldwide
basis.
 
At September 30, 2020,
 
our operations were producing in the U.S., Norway, Canada, Australia,
Indonesia, China, Malaysia,
 
Qatar and Libya.
 
Total production decreased 299 MBOED or 22 percent in the third quarter of 2020,
 
primarily due to:
 
 
Normal field decline.
 
The divestiture of our U.K. assets in the third
 
quarter of 2019, our Australia-West assets in the second
quarter of 2020, and non-core Lower 48 assets in
 
the first quarter of 2020.
 
Production curtailments, primarily from
 
our North American operated assets.
 
Less production in Libya due to the forced shutdown
 
of the Es Sider export terminal and other
 
eastern
export terminals after a period of civil unrest.
 
The decrease in third quarter 2020 production was
 
partly offset by:
 
 
New wells online in the Lower 48, Canada and China.
 
Total production decreased 241 MBOED or 18 percent in the nine-month period of
 
2020,
 
primarily due to:
 
 
Normal field decline.
 
Production curtailments, primarily from
 
our North American operated assets and Malaysia.
 
The divestiture of our U.K. assets in the third
 
quarter of 2019, our Australia-West assets in the second
quarter of 2020, and non-core Lower 48 assets in
 
the first quarter of 2020.
 
Lower production in Libya due to the forced shutdown
 
of the Es Sider export terminal and other
eastern export terminals after a period of civil unrest
 
in the first quarter of 2020.
 
The decrease in production during the nine-month period
 
of 2020 was partly offset by:
 
 
New wells online in the Lower 48, Canada, Norway, Alaska and China.
 
 
Production excluding Libya was 1,066 MBOED in
 
the third quarter of 2020, a decrease
 
of 256 MBOED
compared with the same period of 2019.
 
Adjusting for estimated curtailments of approximately
 
90 MBOED,
closed acquisitions and dispositions and Libya, third
 
quarter 2020 production would have been 1,155
 
MBOED,
a decrease of 46 MBOED or 4 percent compared with
 
the third quarter of 2019.
 
This decrease was primarily
due to normal field decline,
 
partly offset by new wells online in the Lower 48, Canada
 
and China.
 
Production
from Libya averaged 1 MBOED as it remained in
 
force majeure during the third quarter.
 
Production excluding Libya was 1,108 MBOED in
 
the nine-month period of 2020, a decrease
 
of 202 MBOED
compared with the same period of 2019.
 
Adjusting for estimated curtailments of approximately
 
105 MBOED,
closed acquisitions and dispositions and Libya, nine-month
 
period 2020 production would have been 1,186
MBOED, an
 
increase of 6 MBOED compared with the same
 
period a year ago.
 
This increase was primarily
due to new wells online in the Lower 48, Canada,
 
Norway,
 
Alaska, and China, partly offset by normal field
decline.
 
Production from Libya averaged 4 MBOED
 
as it has been in force majeure for most
 
of the year.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
43
Segment Results
Alaska
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Net income (loss) attributable to ConocoPhillips
($MM)
$
(16)
306
(76)
1,152
Average Net Production
Crude oil (MBD)
184
190
179
200
Natural gas liquids (MBD)
14
11
15
15
Natural gas (MMCFD)
14
6
10
7
Total Production
(MBOED)
201
202
195
216
Average Sales Prices
Crude oil ($ per bbl)
$
40.88
62.78
41.92
64.34
Natural gas ($ per MCF)
2.48
3.01
2.71
3.23
 
 
The Alaska segment primarily explores for, produces, transports
 
and markets crude oil, NGLs and natural gas.
 
As of September 30, 2020, Alaska contributed
 
28 percent of our consolidated liquids production
 
and less than
1 percent of our consolidated natural gas production.
 
Earnings from Alaska decreased $322 million
 
in the third quarter of 2020,
 
primarily driven by lower realized
crude oil prices and higher DD&A expense due
 
to increased DD&A rates from price-related
 
downward reserve
revisions.
 
Partly offsetting the decrease in earnings were lower production
 
and operating expenses, primarily
at the Greater Prudhoe Area.
 
 
Earnings from Alaska decreased $1,228 million
 
in the nine-month period of 2020, primarily
 
driven by lower
realized crude oil prices and lower sales volumes
 
due to production curtailments at our
 
operated assets on the
North Slope—the Greater Kuparuk Area (GKA)
 
and Western North Slope (WNS).
 
Partly offsetting the
earnings decrease was lower production and
 
operating expenses primarily associated with
 
lower transportation
and terminaling costs as well as lower wellwork
 
across our assets.
 
 
Average production decreased 1 MBOED in the third quarter of 2020, primarily
 
due to normal field decline,
partly offset by lower planned downtime and new wells
 
online.
 
Average production decreased 21 MBOED in
the nine-month period of 2020, primarily due to
 
normal field decline and curtailments at
 
our operated assets on
the North Slope—GKA and WNS, partly offset by new
 
wells online.
 
Curtailment Update
Based on our economic criteria, we restored curtailed
 
production in Alaska during July.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
44
Lower 48
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
 
($MM)
$
(78)
26
(880)
425
Average Net Production
Crude oil (MBD)
197
277
211
264
Natural gas liquids (MBD)
68
84
74
80
Natural gas (MMCFD)
566
649
577
604
Total Production
(MBOED)
359
469
381
444
Average Sales Prices
Crude oil ($ per bbl)
$
36.43
54.38
34.02
55.63
Natural gas liquids ($ per bbl)
13.51
13.04
10.96
17.03
Natural gas ($ per MCF)
1.63
1.80
1.45
2.19
 
 
The Lower 48 segment consists of operations located
 
in the U.S. Lower 48 states, as well as producing
properties in the Gulf of Mexico.
 
As of September 30, 2020, the Lower 48 contributed
 
41 percent of our
consolidated liquids production and 43 percent
 
of our consolidated natural gas production.
 
Earnings from the Lower 48 decreased $104 million
 
in the third quarter of 2020,
 
primarily due to lower sales
volumes due to normal field decline and production
 
curtailments and lower realized crude oil
 
prices.
 
Partly
offsetting this decrease in earnings were lower exploration
 
expenses due to the absence of $186 million
 
after-
tax of leasehold impairment and dry hole costs
 
associated with our decision to discontinue
 
exploration
activities in the Central Louisiana Austin Chalk
 
trend; lower DD&A expense due to lower volumes,
 
partly
offset by higher DD&A rates due to price-related reserve
 
revisions; and higher other income due to a favorable
$70 million after-tax settlement.
 
Earnings from the Lower 48 decreased $1,305
 
million in the nine-month period of 2020,
 
primarily due to
lower realized crude oil,
 
NGL and natural gas prices;
 
lower crude oil sales volumes due to normal
 
field decline
and production curtailments;
 
and a $399 million after-tax impairment related
 
to certain non-core gas assets in
the Wind River Basin operations area.
 
Partly offsetting this decrease in earnings was the
 
absence of $194
million after-tax of leasehold impairment
 
and dry hole costs associated with our decision
 
to discontinue
exploration activities in the Central Louisiana
 
Austin Chalk trend; lower DD&A expense due to
 
lower
volumes, partly offset by higher DD&A rates due to price-related
 
reserve revisions; and the absence of $120
million of impairments in equity method investments.
 
See Note 8—Impairments and Note 14—Fair
 
Value
Measurement in the Notes to Consolidated Financial
 
Statements, for additional information
 
related to the Wind
River Basin operations area impairment.
 
 
Total average production decreased 110 MBOED and 63 MBOED in the three-
 
and nine-month periods of
2020, respectively, primarily due to normal field decline and production curtailments.
 
Partly offsetting the
production decrease was new production from unconventional
 
assets in the Eagle Ford, Permian and Bakken.
 
Curtailment Update
The third quarter 2020 production impact from
 
curtailments in the Lower 48 was estimated
 
to be 65 MBOED.
 
Based on our economic criteria, we began restoring
 
curtailed volumes in July and ended
 
our curtailment
program by the end of the third quarter.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
45
Canada
Three Months Ended
Nine Months Ended
September 30
September 30
2020*
2019**
2020*
2019**
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
(75)
51
(270)
273
Average Net Production
Crude oil (MBD)
6
1
4
1
Natural gas liquids (MBD)
2
-
2
-
Bitumen (MBD)
49
63
50
59
Natural gas (MMCFD)
43
9
35
8
Total Production
(MBOED)
64
66
62
62
Average Sales Prices
Crude oil ($ per bbl)
$
25.16
-
19.84
-
Natural gas liquids ($ per bbl)
5.99
-
3.60
-
Bitumen ($ per bbl)
15.87
32.54
2.90
34.11
Natural gas ($ per MCF)
0.71
-
0.91
-
*Average sales prices include unutilized transportation costs.
**Average prices for sales of bitumen excludes additional value realized from the purchase and sale of third-party volumes for optimization of
our pipeline capacity between Canada and the U.S. Gulf Coast.
 
 
Our Canadian operations mainly consist of an oil
 
sands development in the Athabasca Region of
 
northeastern
Alberta and a liquids-rich unconventional play
 
in western Canada.
 
As of September 30, 2020, Canada
contributed 8 percent of our consolidated liquids
 
production and 3 percent of our consolidated
 
natural gas
production.
 
Earnings from Canada decreased $126 million
 
and $543 million,
 
respectively, in the three-
 
and nine-month
periods of 2020, primarily due to lower bitumen
 
and crude oil price realizations,
 
lower sales volumes related to
production curtailments,
 
higher DD&A expense associated with increased
 
production from the Montney and
price-related reserve revisions, and lower gain on
 
dispositions related to the absence of
 
contingent payments.
 
Partly offsetting the decreases in earnings in both periods
 
were higher sales volumes from new wells online
 
at
Montney.
 
Total average production decreased 2 MBOED in the third quarter of 2020, primarily
 
due to production
curtailments and a planned turnaround at Surmont,
 
partly offset by new wells online at Montney.
 
Total
average production was flat in the nine-month period
 
of 2020, with production decreases from curtailments
 
at
Surmont offset by new wells online at Montney and lower
 
planned downtime at Surmont.
 
 
Curtailment Update
The third quarter 2020 production impact from
 
curtailments in Canada was estimated to be 15 MBOED
 
net.
 
Based on our economic criteria, we began to restore
 
curtailed production at Surmont in July and ended
 
our
voluntary curtailment program by the end of the third
 
quarter.
 
 
Completed Acquisition
In August 2020, we completed the agreement
 
to acquire additional Montney acreage for cash
 
consideration of
approximately $382 million, subject to customary
 
post-closing adjustments.
 
As part of the agreement, we
assumed approximately $31 million in financing
 
obligations for associated partially owned infrastructure.
 
This
acquisition consisted primarily of undeveloped properties
 
and included
 
140,000 net acres in the liquids-rich
Inga Fireweed asset Montney zone, which is directly
 
adjacent to our existing Montney position.
 
We now have
a Montney acreage position of 295,000 net acres
 
with a 100 percent working interest.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
46
Europe, Middle East and North Africa
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
*
2020
2019
*
Net Income Attributable to ConocoPhillips
($MM)
$
92
2,171
318
3,050
Consolidated Operations
Average Net Production
Crude oil (MBD)
77
149
82
143
Natural gas liquids (MBD)
5
7
5
7
Natural gas (MMCFD)
256
473
276
531
Total Production
(MBOED)
125
235
133
238
Average Sales Prices
Crude oil ($ per bbl)
$
41.79
63.47
43.72
65.17
Natural gas liquids ($ per bbl)
23.50
23.20
20.01
28.65
Natural gas ($ per MCF)
2.40
3.60
2.85
4.98
*Prior periods have been updated to reflect the Middle East Business Unit moving from Asia Pacific to the
 
Europe, Middle East and North
Africa segment.
 
See Note 20
Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements
 
for additional
information.
 
 
The Europe,
 
Middle East and North Africa segment consists
 
of operations principally located in the Norwegian
sector of the North Sea and the Norwegian Sea,
 
Qatar, Libya and commercial operations in the U.K.
 
As of
September 30, 2020, our Europe,
 
Middle East and North Africa operations contributed
 
13 percent of our
consolidated liquids production and 20 percent
 
of our consolidated natural gas production.
 
Earnings for Europe,
 
Middle East and North Africa decreased by $2,079
 
million and $2,732 million in the
three- and nine-month periods of 2020, respectively, primarily due to impacts
 
associated with our U.K.
divestiture in 2019.
 
We recorded a $1.8 billion and $2.1 billion after-tax gain in the three-and nine-month
periods of 2019, respectively, associated with the completion of the sale of two
 
ConocoPhillips U.K.
subsidiaries.
 
In addition to the items detailed above, earnings
 
in both periods decreased due to lower equity
 
in
earnings of affiliates,
 
primarily due to lower LNG sales prices;
 
and lower realized crude oil prices in Norway.
 
 
Consolidated production decreased 110 MBOED and 105 MBOED
 
in the three-
 
and nine-month periods of
2020, respectively, primarily due to our U.K. disposition in the third quarter of
 
2019,
 
lower production in
Libya due to a cessation of production following
 
a period of civil unrest and normal field decline.
 
In addition
to the items detailed above, in the nine-month period
 
of 2020, the production decrease was partly
 
offset by new
wells online
 
in Norway.
 
 
Force Majeure in Libya
Production ceased February 12, 2020, due to a forced
 
shutdown of the Es Sider export terminal
 
and other
eastern export terminals after a period of civil unrest.
 
Force majeure was lifted on October 23, 2020.
 
Plans to
resume production and exports are ongoing.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
47
Asia Pacific
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
*
2020
2019
*
Net Income Attributable to ConocoPhillips
 
($MM)
$
25
443
945
1,220
Consolidated Operations
Average Net Production
Crude oil (MBD)
71
79
70
88
Natural gas liquids (MBD)
-
4
1
4
Natural gas (MMCFD)
322
658
455
633
Total Production
(MBOED)
125
193
147
198
Average Sales Prices
Crude oil ($ per bbl)
$
42.79
62.01
42.94
64.75
Natural gas liquids ($ per bbl)
-
30.13
33.21
38.13
Natural gas ($ per MCF)
5.33
5.78
5.42
6.01
*Prior periods have been updated to reflect the Middle East Business Unit moving to
 
the Europe, Middle East and North Africa segment.
 
See
Note 20—Segment Disclosures and Related Information in the Notes to Consolidated
 
Financial Statements for additional information.
 
 
The Asia Pacific segment has operations in China,
 
Indonesia, Malaysia and Australia.
 
As of September 30,
2020, Asia Pacific contributed 10 percent of our consolidated
 
liquids production and 33 percent of our
consolidated natural gas production.
 
Earnings decreased $418 million in the third
 
quarter of 2020, mainly due to the sale of our disposed
 
Australia-
West assets;
 
the absence of a $164 million income tax benefit
 
related to deepwater incentive tax credits from
 
the
Malaysia Block G; and lower equity in earnings
 
of affiliates, primarily due to lower LNG sales prices.
 
 
Earnings decreased $275 million in the nine-month
 
period of 2020, primarily due to lower realized
 
crude oil and
natural gas prices; lower oil sales volumes, primarily
 
related to curtailments in Malaysia; lower equity in
earnings of affiliates, mainly due to lower LNG sales prices;
 
and the absence of a $164 million income tax
benefit related to deepwater incentive tax credits
 
from the Malaysia Block G.
 
The decrease was partly offset by
a $597 million after-tax gain on disposition related
 
to our Australia-West divestiture.
 
Consolidated production decreased 68 MBOED and
 
51 MBOED in the three-
 
and nine-month periods of 2020,
primarily due to the divestiture of our Australia-West assets, normal field decline, the expiration
 
of the Panyu
production license in China and higher unplanned
 
downtime due to the rupture of a third-party
 
pipeline
impacting gas production from the Kebabangan
 
Field in Malaysia.
 
Partly offsetting these production decreases,
was new production from development activity
 
at Bohai Bay in China and Malaysia.
 
 
Asset Disposition
In the second quarter of 2020, we completed the divestiture
 
of our Australia-West assets and operations, and
based on an effective date of January 1, 2019, we received
 
proceeds of $765 million in May with an additional
$200 million due upon final investment
 
decision of the proposed Barossa development
 
project.
 
Production from
the beginning of the year through the disposition
 
date in May 2020 averaged 43 MBOED and proved
 
reserves
associated with the disposed assets was approximately
 
17 MMBOE at year-end 2019.
 
For additional information
related to this transaction, see Note 4—Asset Acquisitions
 
and Dispositions.
 
 
 
 
 
 
 
 
 
48
Other International
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
(8)
73
14
285
 
 
The Other International segment consists of exploration
 
and appraisal activities in Colombia and Argentina.
 
Earnings from our Other International operations
 
decreased $81 million and $271 million in
 
the three- and
nine-month periods of 2020, respectively.
 
The decrease in earnings was primarily due
 
to the absence of
recognizing $86 million and $317 million after-tax
 
in other income from a settlement award with PDVSA
associated with prior operations in Venezuela,
 
in the three-
 
and nine-month periods of 2019, respectively.
 
See
Note 12—Contingencies and Commitments in
 
the Notes to Consolidated Financial Statements,
 
for additional
information.
 
 
 
 
 
 
 
 
 
 
 
 
49
Corporate and Other
Millions of Dollars
Three Months Ended
Nine Months Ended
September 30
September 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
Net interest expense
$
(179)
(123)
(508)
(450)
Corporate general and administrative expenses
(50)
(34)
(90)
(148)
Technology
(8)
43
(16)
129
Other income (expense)
(153)
100
(1,366)
533
$
(390)
(14)
(1,980)
64
 
 
Net interest expense consists of interest and financing
 
expense, net of interest income and capitalized
 
interest.
 
Net interest expense increased by $56 million
 
and $58 million in the three-and nine-month periods
 
of 2020,
respectively, primarily due to lower interest income related to lower cash and cash
 
equivalent balances and
higher interest expense.
 
Corporate G&A expenses include compensation
 
programs and staff costs.
 
These expenses increased by $16
million and decreased by $58 million in the three-
 
and nine-month periods of 2020,
 
respectively, primarily due
to mark to market adjustments associated with certain
 
compensation programs.
 
Technology includes our investment in new technologies or businesses, as well as licensing
 
revenues.
 
Activities are focused on both conventional and tight
 
oil reservoirs, shale gas, heavy oil, oil
 
sands, enhanced
oil recovery, as well as LNG.
 
Earnings from Technology decreased by $51 million and $145 million in the
three-and nine-month periods
 
of 2020, respectively, primarily due to lower licensing revenues.
 
 
Other income (expense) or “Other” includes certain
 
corporate tax-related items, 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.
 
“Other”
 
decreased by $253 million in the
third quarter of 2020,
 
primarily due to an unrealized loss of $162 million
 
after-tax on our CVE common shares
in the third quarter of 2020, and the absence of a
 
$116 million after-tax gain on those shares in the third quarter
of 2019.
 
In the nine-month period of 2020, “Other” decreased
 
by $1,899 million,
 
primarily due to an
unrealized loss of $1,302 million after-tax
 
on our CVE common shares in the nine-month
 
period of 2020, and
the absence of a $489 million after-tax gain on those
 
shares in the nine-month period of 2019.
 
 
 
 
 
 
 
 
 
 
50
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
September 30
December 31
2020
2019
Short-term debt
$
482
105
Total debt
15,387
14,895
Total equity
30,783
35,050
Percent of total debt to capital*
33
%
30
Percent of floating-rate debt to total debt
7
%
5
*Capital includes total debt and total equity.
 
 
To meet our short-
 
and long-term liquidity requirements, we look
 
to a variety of funding sources, including
cash generated from operating activities,
 
our commercial paper and credit facility programs,
 
and our ability to
sell securities using our shelf registration
 
statement.
 
During the first nine months of 2020, the primary uses
 
of
our available cash were $3,657 million to support
 
our ongoing capital expenditures and investments
 
program,
including the $382 million of cash used to acquire
 
additional Montney acreage, $1,089 million
 
for net
purchases of investments,
 
$726 million to repurchase common stock,
 
and $1,367 million to pay dividends.
 
During the first nine months of 2020, our cash,
 
cash equivalents and restricted cash decreased
 
by $2,566
million to $2,796 million.
 
 
We entered the year with a strong balance sheet including cash and cash equivalents
 
of over $5 billion, short-
term investments of $3 billion, and an undrawn
 
credit facility of $6 billion, totaling
 
approximately $14 billion
in available liquidity.
 
This strong foundation allowed us to be measured
 
in our response to the sudden change
in business environment as we exited the first
 
quarter of 2020.
 
In response to the oil market downturn
 
earlier
this year, we announced the following capital, operating cost
 
and share repurchase reductions.
 
We reduced our
2020 operating plan capital expenditures by a total
 
of $2.3 billion, or approximately thirty-five
 
percent of the
original guidance.
 
We suspended our share repurchase program, further reducing cash outlays by
approximately $2 billion.
 
We also reduced our operating costs by approximately $0.6 billion, or roughly ten
percent of the original 2020 guidance.
 
Collectively, these actions represent a reduction in 2020 cash uses of
approximately $5 billion versus the original operating
 
plan.
 
 
Considering the weakness in oil prices during the
 
second quarter of 2020, we established a
 
framework for
evaluating and implementing economic curtailments,
 
which resulted in taking an additional significant
 
step of
curtailing production, predominantly from
 
operated North American assets.
 
Due to our strong balance sheet,
we were in an advantaged position to forgo some production
 
and cash flow in anticipation of receiving higher
cash flows for those volumes in the future.
 
Based on our economic criteria, we began restoring
 
production
from voluntary curtailments in July, and with oil stabilizing around $40 per barrel, we
 
ended our curtailment
program by the end of the third quarter.
 
 
At the end of the third quarter, we had cash and cash equivalents of
 
$2.5 billion, short-term investments of
$4.0 billion, and available borrowing capacity under
 
our credit facility of $5.7 billion, totaling
 
over $12 billion
of liquidity.
 
We believe current cash balances and cash generated by operations, the recent adjustments
 
to our
operating plan, together with access to external sources
 
of funds as described below in the “Significant
 
Sources
of Capital” section, will be sufficient to meet our funding
 
requirements in the near- and long-term, including
our capital spending program, dividend payments
 
and required debt payments.
 
 
 
 
 
51
Significant Sources of Capital
 
Operating Activities
 
Cash provided by operating activities was $3.1 billion
 
for the first nine months of 2020, compared with $8.1
billion for the corresponding period of 2019.
 
The decrease in cash provided by operating
 
activities is primarily
due to lower realized commodity prices, normal
 
field decline, production curtailments,
 
the divestiture of our
U.K. and Australia-West assets, and the absence in 2020 of payments under our settlement
 
agreement with
PDVSA.
 
 
 
Our short-
 
and long-term operating cash flows are highly
 
dependent upon prices for crude oil, bitumen, natural
gas, LNG and NGLs.
 
Prices and margins in our industry have historically
 
been volatile and are driven by
market conditions over which we have no control.
 
Absent other mitigating factors, as these prices
 
and margins
fluctuate, we would expect a corresponding change
 
in our operating cash flows.
 
The level of absolute production volumes, as well
 
as product and location mix, impacts our cash flows.
 
Production levels are impacted by such factors as
 
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; global pandemics and
associated demand decreases; weather-related disruptions;
 
and the addition of proved reserves through
exploratory success and their timely and cost-effective
 
development.
 
While we actively manage these factors,
production levels can cause variability in cash flows,
 
although generally this variability has not been
 
as
significant as that caused by commodity prices.
 
 
To maintain or grow our production volumes, we must continue to add to our
 
proved reserve base.
 
Due to
recent capital reductions, our reserve replacement could
 
be delayed thus limiting our ability to
 
replace depleted
reserves.
 
 
Investing Activities
Proceeds from asset sales in the first nine months
 
of 2020 were $1.3 billion
 
compared with $2.9 billion in the
corresponding period of 2019.
 
In the second quarter of 2020, we completed
 
the divestiture of our Australia-
West assets and operations.
 
Based on an effective date of January 1, 2019 and customary
 
closing adjustments,
we received cash proceeds of $765 million in
 
the second quarter with another $200 million
 
payment due upon
final investment decision of the proposed Barossa
 
development project.
 
In the first quarter of 2020, proceeds
from asset sales were $549 million, which included
 
the sale of our Niobrara interests and Waddell Ranch
interests in the Lower 48 for proceeds of $359 million
 
and $184 million, respectively.
 
See Note 4—Asset
Acquisitions and Dispositions in the Notes to Consolidated
 
Financial Statements, for additional information
 
on
these transactions.
 
Proceeds from asset sales in the first nine months
 
of 2019 were $2.9 billion,
 
which consisted primarily of $2.2
billion related to the sale of two ConocoPhillips
 
U.K. subsidiaries, $350 million from the sale of our
 
30 percent
interest in the Greater Sunrise Fields
 
and $77 million of contingent payments from
 
Cenovus Energy.
 
Commercial Paper and Credit Facilities
We have a revolving credit facility totaling $6.0 billion, expiring in May 2023.
 
Our revolving credit facility
may be used for direct bank borrowings, the issuance
 
of letters of credit totaling up to $500 million, or
 
as
support for our commercial paper program.
 
The revolving credit facility is broadly syndicated
 
among financial
institutions and does not contain any material
 
adverse change provisions or any covenants
 
requiring
maintenance of specified financial ratios or credit
 
ratings.
 
The facility agreement contains a cross-default
provision relating to the failure to pay principal or interest
 
on other debt obligations of $200 million or more
by ConocoPhillips, or any of its consolidated subsidiaries.
 
The amount of the facility is not subject to
redetermination prior to its expiration date.
 
 
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
 
 
52
certain designated banks in the U.S.
 
The agreement calls for commitment fees
 
on available, but unused,
amounts.
 
The agreement also contains early termination
 
rights if our current directors or their approved
successors cease to be a majority of the Board of
 
Directors.
 
The revolving credit facility supports the ConocoPhillips
 
Company $6.0 billion commercial paper program,
which is primarily a funding source for short-term
 
working capital needs.
 
Commercial paper maturities are
generally limited to 90 days.
 
With $300 million of commercial paper outstanding and no direct
 
borrowings or
letters of credit, we had $5.7 billion in available
 
borrowing capacity under the revolving credit facility
 
at
September 30, 2020.
 
We may consider issuing additional commercial paper in the future to supplement
 
our
cash position.
 
Despite recent volatility and price weakness for energy issuers
 
in the debt capital markets, we believe the
company continues to have access to the markets
 
based on the composition of our balance sheet
 
and asset
portfolio.
 
In October 2020, S&P affirmed its “A” rating on our senior
 
long-term debt and revised its outlook to “stable”
from “negative,” Fitch affirmed its rating of “A” with a “stable”
 
outlook and Moody’s affirmed its rating of
“A3” with a “stable” outlook.
 
We do not have any ratings triggers on any of our corporate debt that would
cause an automatic default, and thereby impact
 
our access to liquidity, in the event of a downgrade of our
credit rating.
 
If our credit rating were downgraded, it could
 
increase the cost of corporate debt available to
 
us
and potentially restrict our access to the commercial
 
paper and debt capital markets.
 
If our credit rating were
to deteriorate to a level prohibiting us from
 
accessing the commercial paper and debt capital
 
markets, 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 September 30, 2020 and December 31, 2019, we had
 
direct bank letters of credit of
$240 million and $277 million, respectively, which secured performance
 
obligations related to various
purchase commitments incident to the ordinary conduct
 
of business.
 
In the event of credit ratings downgrades,
we may be required to post additional letters
 
of credit.
 
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which we
 
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 11—Guarantees, in
 
the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
 
 
 
 
 
 
 
 
 
 
 
 
 
53
Guarantor Summarized 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.
 
 
In March of 2020, the SEC adopted amendments
 
to simplify the financial disclosure requirements
 
for
guarantors and issuers of guaranteed securities
 
registered under Rule 3-10 of Regulation S-X.
 
Based on our
evaluation of our existing guarantee relationships,
 
we qualify for the transition to alternative disclosures.
 
We
have elected early voluntary compliance with
 
the final amendments beginning in the third
 
quarter of 2020.
 
Accordingly, condensed consolidating information by guarantor and issuer of guaranteed
 
securities will no
longer be reported, and alternative disclosures
 
of summarized financial information for the
 
consolidated
Obligor Group is presented.
 
The following tables present summarized financial
 
information for the Obligor
Group, as defined below:
 
 
The Obligor Group will reflect guarantors and
 
issuers of guaranteed securities consisting of
ConocoPhillips, ConocoPhillips Company and
 
Burlington Resources LLC.
 
Consolidating adjustments for elimination
 
of investments in and transactions between the collective
guarantors and issuers of guaranteed securities
 
are reflected in the balances of the summarized
financial
 
information.
 
Non-Obligated Subsidiaries are excluded from
 
this presentation.
 
Transactions and balances reflecting
activity between the Obligors and Non-Obligated
 
Subsidiaries are presented below:
 
 
Summarized Income Statement Data
Millions of Dollars
Nine Months Ended
September 30, 2020
Revenues and Other Income
$
5,690
Income (loss) before income taxes
(2,018)
Net income (loss)
(1,929)
Net Income (Loss) Attributable to ConocoPhillips
(1,929)
 
 
Summarized Balance Sheet Data
Millions of Dollars
September 30
2020
December 31
2019
Current assets
$
7,890
10,829
Amounts due from Non-Obligated Subsidiaries, current
473
732
Noncurrent assets
40,026
43,194
Amounts due from Non-Obligated Subsidiaries, noncurrent
7,622
7,977
Current liabilities
3,247
3,813
Amounts due to Non-Obligated Subsidiaries, current
1,361
1,836
Noncurrent liabilities
20,444
21,787
Amounts due to Non-Obligated Subsidiaries, noncurrent
5,725
6,974
 
 
 
 
 
 
 
 
 
 
 
 
54
Capital Requirements
 
For information about our capital expenditures
 
and investments, see the “Capital Expenditures”
 
section.
 
Our debt balance at September 30, 2020,
 
was $15,387 million, compared with $14,895 million
 
at December
31, 2019.
 
Maturities of debt for the remainder of 2020,
 
and for each of the years 2021 through 2024, are:
 
$367
million, $281 million, $998 million, $256 million
 
and $577 million, respectively.
 
 
On February 4, 2020, we announced a quarterly
 
dividend of 42 cents per share.
 
The dividend was paid on
March 2, 2020, to stockholders of record at the close
 
of business on February 14, 2020.
 
On April 30, 2020, we
announced a quarterly dividend of 42 cents per share.
 
The dividend was paid on June 1, 2020, to
 
stockholders
of record at the close of business on May 11, 2020.
 
On July 8, 2020, we announced a quarterly dividend of
 
42
cents per share, payable September 1, 2020, to stockholders
 
of record at the close of business on July 20,
 
2020.
 
On October 9, 2020, we announced an increase to
 
our quarterly dividend from 42 cents per share
 
to 43 cents
per share.
 
The dividend is payable on December 1, 2020
 
to shareholders of record as of October 19, 2020.
 
 
In late 2016, we initiated our current share repurchase
 
program.
 
As of September 30, 2020, we had announced
a total authorization to repurchase $25 billion
 
of our common stock.
 
As of December 31, 2019, we had
repurchased $9.6 billion of shares.
 
In the first quarter of 2020, we repurchased
 
an additional $0.7 billion of
shares before suspending repurchases during
 
the second and third quarters of 2020.
 
On September 30, 2020,
we announced our intent to resume share repurchases;
 
however, we recently announced the pending
acquisition of Concho, and our suspension of share
 
repurchases until after the transaction closes.
 
 
Capital Expenditures
Millions of Dollars
Nine Months Ended
September 30
2020
2019
Alaska
$
882
1,207
Lower 48
1,398
2,613
Canada
593
315
Europe, Middle East and North Africa
410
537
Asia Pacific
280
322
Other International
66
1
Corporate and Other
28
46
Capital expenditures and investments
$
3,657
5,041
 
 
During the first nine months of 2020, capital expenditures
 
and investments supported key exploration and
development programs, primarily:
 
 
Development,
 
appraisal and exploration activities in the
 
Lower 48, including Eagle Ford, Permian
Unconventional and Bakken.
 
Appraisal,
 
exploration and development activities
 
in Alaska related to the Western North Slope;
development activities in the Greater Kuparuk
 
Area and the Greater Prudhoe Area.
 
 
Development and exploration activities across
 
assets in Norway.
 
Appraisal activities in the liquids-rich portion
 
of the Montney in Canada and optimization
 
of oil sands
development.
 
Continued development in China, Malaysia,
 
Australia and Indonesia.
 
 
Lease acquisition and appraisal activities
 
in Argentina.
 
 
 
55
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
In response to the
oil market downturn earlier this year, we announced capital
 
expenditure reductions totaling $2.3 billion.
 
Full
year 2020 operating plan capital is now expected
 
to be $4.3 billion.
 
This does not include approximately $0.5
billion of capital for acquisitions completed during
 
the year, of which $0.4 billion was for bolt-on acreage in
the liquids rich area of the Montney.
 
In August 2020, we completed the acquisition
 
of additional Montney acreage in Canada for $382 million
 
after
customary adjustments, plus the assumption of
 
$31 million in financing obligations associated
 
with partially
owned infrastructure.
 
See Note 4—Asset Acquisitions and Dispositions,
 
in the Notes to Consolidated
Financial Statements, for additional information.
 
 
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.
 
We accrue receivables for insurance or other third-party recoveries when applicable.
 
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.
 
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, legal and
 
tax 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 legal and tax matters are subject to
 
change as events evolve and as additional
 
information becomes
available during the administrative and litigation
 
processes.
 
For information on other contingencies, see
Note 12—Contingencies and Commitments, in
 
the Notes to Consolidated Financial Statements.
 
 
Legal and Tax Matters
We are subject to various lawsuits and claims including but not limited to matters
 
involving oil and gas royalty
and severance tax payments, gas measurement and
 
valuation methods, contract disputes,
 
environmental
damages, climate change, personal injury, and property damage.
 
Our primary exposures for such matters
relate to alleged royalty and tax underpayments
 
on certain federal, state and privately owned
 
properties and
claims of alleged environmental contamination
 
from historic operations.
 
We will continue to defend ourselves
vigorously in these matters.
 
Our legal organization applies its knowledge, experience
 
and professional judgment to the specific
characteristics of our cases, employing a litigation
 
management process to manage and monitor the
 
legal
proceedings against us.
 
Our process facilitates the early evaluation and quantification
 
of potential exposures in
individual cases.
 
This process also enables us to track those cases that
 
have been scheduled for trial and/or
mediation.
 
Based on professional judgment and experience
 
in using these litigation management tools and
available information about current developments
 
in all our cases, our legal organization regularly assesses
 
the
adequacy of current accruals and determines if
 
adjustment of existing accruals, or establishment
 
of new
accruals, is required.
 
 
 
 
56
Environmental
We are subject to the same numerous international, federal, state and local environmental
 
laws and regulations
as other companies in our industry.
 
For a discussion of the most significant
 
of these environmental laws and
regulations, including those with associated remediation
 
obligations, see the “Environmental” section in
Management’s Discussion and Analysis of Financial Condition and Results
 
of Operations on pages 60–62 of
our 2019 Annual Report on Form 10-K.
 
We occasionally receive requests for information or notices of potential liability
 
from the EPA and state
environmental agencies alleging that we are
 
a potentially responsible party under the Federal
 
Comprehensive
Environmental Response, Compensation and Liability
 
Act (CERCLA) or an equivalent state statute.
 
On
occasion, we also have been made a party to cost
 
recovery litigation by those agencies or by private
 
parties.
 
These requests, notices and lawsuits assert potential
 
liability for remediation costs at various sites
 
that typically
are not owned by us, but allegedly contain waste attributable
 
to our past operations.
 
As of September 30,
2020, there were 15 sites around the U.S. in which
 
we were identified as a potentially responsible
 
party under
CERCLA and comparable state laws.
 
At September 30, 2020, our balance sheet included
 
a total environmental accrual of $177 million,
 
compared
with $171 million at December 31, 2019, 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 GHG reduction.
 
These proposed or
promulgated laws apply or could apply in countries
 
where we have interests or may have interests
 
in the future.
 
Laws in this field continue to evolve, and while
 
it is not possible to accurately estimate either
 
a timetable for
implementation or our future compliance costs
 
relating to implementation, such laws, if
 
enacted, could have a
material impact on our results of operations and
 
financial condition.
 
Examples of legislation and precursors
for possible regulation that do or could affect our operations
 
include:
 
 
The EPA’s
 
and U.S. Department of Transportation’s joint promulgation of a Final Rule on April
 
1,
2010, that triggered 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.
 
New Mexico’s Energy,
 
Minerals and Natural Resources Department
 
has proposed natural gas waste
rules as part of New Mexico’s statewide, enforceable regulatory framework
 
to secure reductions in oil
and gas sector emissions and to prevent natural gas
 
waste from new and existing sources.
 
For other examples of legislation or precursors for
 
possible regulation and factors on which
 
the ultimate impact
on our financial performance will depend, see the
 
“Climate Change” section in Management’s Discussion and
Analysis of Financial Condition and Results of Operations
 
on pages 63–65 of our 2019 Annual Report on
Form 10-K.
 
We announced in October 2020 the adoption of a Paris-aligned climate risk framework
 
as part of our continued
commitment to ESG excellence.
 
This comprehensive climate risk strategy
 
should enable us to sustainably
meet global energy demand while delivering competitive
 
returns through the energy transition.
 
We have set a
target to reduce our gross operated (scope 1 and 2) emissions
 
intensity by 35 to 45 percent from 2016 levels
 
by
2030, with an ambition to achieve net zero by
 
2050 for operated emissions.
 
We are advocating for reduction
of scope 3 end-use emissions intensity through
 
our support for a U.S. carbon price.
 
We have joined the World
Bank Flaring Initiative to work towards zero routine
 
flaring of gas by 2030.
 
We are committed to take ESG
 
57
leadership to the next level as the first U.S.-based
 
oil and gas company to adopt a Paris-aligned
 
climate risk
strategy.
 
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 our October 2020 Paris
aligned-climate risk framework announcement,
 
we reaffirmed our commitment to the Climate Leadership
Council.
 
 
Beginning in 2017, cities, counties, governments
 
and other entities in several states in the U.S. have
 
filed
lawsuits against oil and gas companies, including
 
ConocoPhillips, seeking compensatory damages
 
and
equitable relief to abate alleged climate change impacts.
 
Additional lawsuits with similar allegations
 
are
expected to be filed.
 
The amounts claimed by plaintiffs are unspecified and
 
the legal and factual issues
involved in these cases are unprecedented.
 
ConocoPhillips believes these lawsuits are factually
 
and legally
meritless and are an inappropriate vehicle to address
 
the challenges associated with climate
 
change and will
vigorously defend against such lawsuits.
 
Several Louisiana parishes and the State of Louisiana
 
have filed 43 lawsuits under Louisiana’s State and Local
Coastal Resources Management Act (SLCRMA)
 
against oil and gas companies, including ConocoPhillips,
seeking compensatory damages for contamination
 
and erosion of the Louisiana coastline
 
allegedly caused by
historical oil and gas operations.
 
ConocoPhillips entities are defendants in
 
22 of the lawsuits and will
vigorously defend against them.
 
Because Plaintiffs’ SLCRMA theories are unprecedented,
 
there is uncertainty
about these claims (both as to scope and damages)
 
and any potential financial impact on the company.
 
 
CAUTIONARY STATEMENT
 
FOR THE PURPOSES OF THE “SAFE HARBOR”
 
PROVISIONS OF
THE PRIVATE
 
SECURITIES LITIGATION REFORM ACT OF 1995
 
This report includes forward-looking statements
 
within the meaning of Section 27A of the Securities
 
Act of
1933 and Section 21E of the Securities Exchange Act
 
of 1934.
 
All statements other than statements of
historical fact included or incorporated by reference
 
in this report, including, without limitation,
 
statements
regarding our future financial position, business
 
strategy, budgets, projected revenues, projected costs and
plans, objectives of management for future operations,
 
the anticipated benefits of the proposed transaction
between us and Concho, the anticipated impact
 
of the proposed transaction on the combined company’s
business and future financial and operating results,
 
the expected amount and the timing of synergies from
 
the
proposed transaction, and the anticipated closing
 
date for the proposed transaction are forward-looking
statements.
 
Examples of forward-looking statements contained
 
in this report include our expected production
growth and outlook on the business environment
 
generally, our expected capital budget and capital
expenditures, and discussions concerning future
 
dividends.
 
You can often identify our forward-looking
statements by the words “anticipate,” “estimate,”
 
“believe,” “budget,” “continue,” “could,”
 
“intend,” “may,”
“plan,” “potential,” “predict,” “seek,” “should,”
 
“will,” “would,” “expect,” “objective,” “projection,”
“forecast,” “goal,” “guidance,” “outlook,” “effort,” “target”
 
and similar expressions.
 
 
 
58
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
 
and uncertainties, including, but not
limited to, the following:
 
 
 
The impact of public health crises, including pandemics
 
(such as COVID-19) and epidemics and any
related company or government policies or
 
actions.
 
Global and regional changes in the demand, supply, prices, differentials or other market
 
conditions
affecting oil and gas, including changes resulting from a public
 
health crisis or from the imposition or
lifting of crude oil production quotas or other
 
actions that might be imposed by OPEC
 
and other
producing countries and the resulting company
 
or third-party actions in response to such changes.
 
Fluctuations in crude oil, bitumen, natural gas,
 
LNG and NGLs prices, including a prolonged
 
decline
in these prices relative to historical or future
 
expected levels.
 
The impact of significant declines in prices for
 
crude oil, bitumen, natural gas, LNG and NGLs,
 
which
may result in recognition of impairment charges on our
 
long-lived assets, leaseholds and
nonconsolidated equity investments.
 
Potential failures or delays in achieving expected
 
reserve or production levels from existing
 
and future
oil and gas developments, including due to operating
 
hazards, drilling risks and the inherent
uncertainties in predicting reserves and reservoir
 
performance.
 
Reductions in reserves replacement rates, whether
 
as a result of the significant declines in commodity
prices or otherwise.
 
Unsuccessful exploratory drilling activities
 
or the inability to obtain access to exploratory acreage.
 
Unexpected changes in costs or technical requirements
 
for constructing, modifying or operating E&P
facilities.
 
Legislative and regulatory initiatives
 
addressing environmental concerns, including initiatives
addressing the impact of global climate change or further
 
regulating hydraulic fracturing, methane
emissions, flaring or water disposal.
 
Lack of, or disruptions in, adequate and reliable
 
transportation for our crude oil, bitumen, natural
 
gas,
LNG and NGLs.
 
Inability to timely obtain or maintain permits,
 
including those necessary for construction, drilling
and/or development, or inability to make capital
 
expenditures required to maintain compliance
 
with
any necessary permits or applicable laws or regulations.
 
Failure to complete definitive agreements and feasibility
 
studies for, and to complete construction of,
announced and future E&P and LNG development
 
in a timely manner (if at all) or on budget.
 
Potential disruption or interruption of our operations
 
due to accidents, extraordinary weather events,
civil unrest, political events, war, terrorism, cyber attacks,
 
and information technology failures,
constraints or disruptions.
 
Changes in international monetary conditions and
 
foreign currency exchange rate fluctuations.
 
Changes in international trade relationships,
 
including the imposition of trade restrictions
 
or tariffs
relating to crude oil, bitumen, natural gas, LNG,
 
NGLs and any materials or products (such as
aluminum and steel) used in the operation of our
 
business.
 
Substantial investment in and development use
 
of, competing or alternative energy sources, including
as a result of existing or future environmental
 
rules and regulations.
 
Liability for remedial actions, including removal
 
and reclamation obligations, under existing
 
and
future environmental regulations and litigation.
 
Significant operational or investment changes imposed
 
by existing or future environmental
 
statutes
and regulations, including international agreements
 
and national or regional legislation and regulatory
measures to limit or reduce GHG emissions.
 
59
 
Liability resulting from litigation, including the
 
potential for litigation related to the
 
proposed
transaction, or our failure to comply with applicable
 
laws and regulations.
 
 
General domestic and international economic and
 
political developments, including armed
 
hostilities;
expropriation of assets; changes in governmental
 
policies relating to crude oil, bitumen, natural
 
gas,
LNG and NGLs pricing, regulation or taxation;
 
and other political, economic or diplomatic
developments.
 
Volatility
 
in the commodity futures markets.
 
Changes in tax and other laws, regulations (including
 
alternative energy mandates), or royalty rules
applicable to our business.
 
Competition and consolidation in the oil and gas E&P
 
industry.
 
Any limitations on our access to capital or increase
 
in our cost of capital, including as a result
 
of
illiquidity or uncertainty in domestic or international
 
financial markets.
 
Our inability to execute, or delays in the completion,
 
of any asset dispositions or acquisitions
 
we elect
to pursue.
 
 
Potential failure to obtain, or delays in obtaining, any
 
necessary regulatory approvals for
 
pending or
future asset dispositions or acquisitions,
 
or that such approvals may require modification
 
to the terms
of the transactions or the operation of our remaining
 
business.
 
Potential disruption of our operations as a result
 
of pending or future asset dispositions or acquisitions,
including the diversion of management time and attention.
 
Our inability to deploy the net proceeds from any
 
asset dispositions that are pending or
 
that we elect to
undertake in the future in the manner and timeframe
 
we currently anticipate, if at all.
 
Our inability to liquidate the common stock issued
 
to us by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem
 
acceptable, or at all.
 
The operation and financing of our joint ventures.
 
The ability of our customers and other contractual
 
counterparties to satisfy their obligations to
 
us,
including our ability to collect payments when
 
due from the government of Venezuela or PDVSA.
 
 
Our inability to realize anticipated cost savings and
 
capital expenditure reductions.
 
The inadequacy of storage capacity for our products,
 
and ensuing curtailments, whether voluntary
 
or
involuntary, required to mitigate this physical constraint.
 
Our ability to successfully integrate Concho’s business.
 
The risk that the expected benefits and cost
 
reductions associated with the proposed transaction
 
may
not be fully achieved in a timely manner, or at all.
 
The risk that we or Concho will be unable to retain
 
and hire key personnel.
 
The risk associated with our and Concho’s ability to obtain the approvals of
 
our respective
stockholders required to consummate the proposed
 
transaction and the timing of the closing
 
of the
proposed transaction, including the risk that
 
the conditions to the transaction are not satisfied
 
on a
timely basis or at all or the failure of the transaction
 
to close for any other reason or to close on the
anticipated terms, including the anticipated tax treatment.
 
The risk that any regulatory approval, consent or
 
authorization that may be required for
 
the proposed
transaction is not obtained or is obtained subject
 
to conditions that are not anticipated.
 
Unanticipated difficulties or expenditures relating to
 
the transaction, the response of business
 
partners
and retention as a result of the announcement and
 
pendency of the transaction.
 
Uncertainty as to the long-term value of our common
 
stock.
 
The diversion of management time on transaction-related
 
matters.
 
The risk factors generally described in Part II—Item
 
1A in this report, in Part I—Item 1A in our 2019
Annual Report on Form 10-K, in our Forms 8-K
 
filed with the SEC on May 20, 2020 and September
8, 2020, respectively, and any additional risks described in our other filings with
 
the SEC.
 
 
Item 3.
 
QUANTITATIVE
 
AND QUALITATIVE
 
DISCLOSURES ABOUT MARKET RISK
 
Information about market risks for the nine months
 
ended September 30, 2020, does not differ materially
 
from
that discussed under Item 7A in our 2019 Annual Report
 
on Form 10-K.
 
 
60
Item 4.
 
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 SEC 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 September 30,
2020, with the participation of our management,
 
our Chairman and Chief Executive Officer (principal
executive officer) and our Executive Vice President and Chief Financial Officer (principal
 
financial officer)
carried out an evaluation, pursuant to Rule 13a-15(b)
 
of the Act, of ConocoPhillips’ disclosure controls
 
and
procedures (as defined in Rule 13a-15(e) of the Act).
 
Based upon that evaluation, our Chairman and
 
Chief
Executive Officer and our Executive Vice President and Chief Financial Officer concluded
 
our disclosure
controls and procedures were operating effectively as of September
 
30, 2020.
 
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.
 
 
PART
 
II.
 
OTHER INFORMATION
 
Item 1.
 
LEGAL PROCEEDINGS
 
There are no new material legal proceedings
 
or material developments with respect to matters
 
previously
disclosed in Item 3 of our 2019 Annual Report on
 
Form 10-K.
 
 
Item 1A.
 
RISK FACTORS
 
Other than the risk factors set forth below, there have been no material changes
 
to the risk factors disclosed in
our Annual Report on Form 10-K for the fiscal
 
year ended December 31, 2019.
 
Risks Related to the Business
 
Existing and future laws, regulations and internal
 
initiatives relating to global climate change,
 
such as
limitations on GHG emissions, may impact or limit
 
our business plans, result in significant expenditures,
promote alternative uses of energy or reduce demand
 
for our products.
 
Continuing political and social attention to the
 
issue of global climate change has resulted in
 
both existing and
pending international agreements and national,
 
regional or local legislation and regulatory
 
measures to limit
GHG emissions, such as cap and trade regimes, carbon
 
taxes, restrictive permitting, increased fuel efficiency
standards and incentives or mandates for renewable
 
energy.
 
For example, in December 2015, the U.S. joined
the international community at the 21st Conference
 
of the Parties of the United Nations Framework
Convention on Climate Change in Paris that
 
prepared an agreement requiring member countries
 
to review and
represent a progression in their intended GHG
 
emission reduction goals every five years
 
beginning in 2020.
 
While the U.S. announced its intention to withdraw
 
from the Paris Agreement, there is no guarantee
 
that the
commitments made by the U.S. will not be implemented,
 
in whole or in part, by U.S. state and local
governments or by major corporations headquartered
 
in the U.S.
 
In addition, our operations continue in
countries around the world which are party to, and
 
have not announced an intent to withdraw
 
from, the Paris
Agreement.
 
The implementation of current agreements and
 
regulatory measures, as well as any future
agreements or measures addressing climate
 
change and GHG emissions, may adversely impact
 
the demand for
our products, impose taxes on our products or operations
 
or require us to purchase emission credits
 
or reduce
emission of GHGs from our operations.
 
As a result, we may experience declines in commodity
 
prices or incur
substantial capital expenditures and compliance,
 
operating, maintenance and remediation costs,
 
any of which
may have an adverse effect on our business and results
 
of operations.
 
61
 
Compliance with the various climate change related
 
internal initiatives described in the “Business
 
Environment
and Executive Overview” section of Management’s Discussion and Analysis
 
of Financial Condition and
Results of Operations may increase costs, require
 
us to purchase emission credits, or limit
 
or impact our
business plans, potentially resulting in the reduction
 
to the economic end-of-field life of certain
 
assets and an
impairment of the associated net book value.
 
Additionally, increasing attention to global climate change has resulted in pressure
 
upon shareholders,
financial institutions and/or financial markets
 
to modify their relationships with oil and gas companies
 
and to
limit investments and/or funding to such companies,
 
which could increase our costs or otherwise
 
adversely
affect our business and results of operations.
 
 
Furthermore, increasing attention to global climate
 
change has resulted in an increased likelihood
 
of
governmental investigations and private litigation,
 
which could increase our costs or otherwise adversely
 
affect
our business.
 
Beginning in 2017, cities, counties, governments
 
and other entities in several states in the U.S.
have filed lawsuits against oil and gas companies,
 
including ConocoPhillips, seeking compensatory
 
damages
and equitable relief to abate alleged climate change
 
impacts.
 
Additional lawsuits with similar allegations
 
are
expected to be filed.
 
The amounts claimed by plaintiffs are unspecified
 
and the legal and factual issues
involved in these cases are unprecedented.
 
ConocoPhillips believes these lawsuits are factually
 
and legally
meritless and are an inappropriate vehicle to address
 
the challenges associated with climate
 
change and will
vigorously defend against such lawsuits.
 
The ultimate outcome and impact to us cannot
 
be predicted with
certainty, and we could incur substantial legal costs associated with defending these
 
and similar lawsuits in the
future.
 
In addition, although we design and operate our
 
business operations to accommodate expected
 
climatic
conditions, to the extent there are significant
 
changes in the earth’s climate, such as more severe or frequent
weather conditions in the markets where we operate
 
or the areas where our assets reside, we could
 
incur
increased expenses, our operations could be adversely
 
impacted, and demand for our products could
 
fall.
For more information on legislation or precursors
 
for possible regulation relating to global climate
 
change that
affect or could affect our operations and a description of the company’s response, see the
 
“Contingencies—
Climate Change” section of Management’s Discussion and Analysis of
 
Financial Condition and Results of
Operations.
 
 
Our business has been, and will continue to
 
be, affected by the coronavirus (COVID-19) pandemic.
 
The COVID-19 outbreak and the measures put
 
in place to address it have negatively impacted
 
the global
economy, disrupted global supply chains, reduced global demand for oil
 
and gas, and created significant
volatility and disruption of financial and commodity
 
markets.
 
Public health officials have recommended or
mandated certain precautions to mitigate
 
the spread of COVID-19, including limiting non-essential
 
gatherings
of people, ceasing all non-essential travel
 
and issuing “social or physical distancing” guidelines,
 
“shelter-in-
place” orders and mandatory closures or reductions
 
in capacity for non-essential businesses.
 
The full impact of
the COVID-19 pandemic remains uncertain
 
and will depend on the severity, location and duration of the
effects and spread of the disease, the effectiveness and duration
 
of actions taken by authorities to contain the
virus or treat its effect, and how quickly and to what
 
extent economic conditions improve.
 
According to the
National Bureau of Economic Research, as a result
 
of the pandemic and its broad reach across the
 
entire
economy, the U.S. entered a recession in early 2020.
 
We have already been impacted by the COVID-19 pandemic.
 
See Management’s Discussion and Analysis of
Financial Condition and Results of Operations, for
 
additional information on how we have
 
been impacted and
the steps we have taken in response.
 
 
Our business is likely to be further negatively
 
impacted by the COVID-19 pandemic.
 
These impacts could
include but are not limited to:
 
 
Continued reduced demand for our products
 
as a result of reductions in travel and commerce;
 
62
 
Disruptions in our supply chain due in part to scrutiny
 
or embargoing of shipments from infected areas
or invocation of force majeure clauses in commercial
 
contracts due to restrictions imposed as a result
of the global response to the pandemic;
 
Failure of third parties on which we rely, including our suppliers, contract
 
manufacturers, contractors,
joint venture partners and external business partners,
 
to meet their obligations to the company, or
significant disruptions in their ability to
 
do so, which may be caused by their own financial
 
or
operational difficulties or restrictions imposed in
 
response to the disease outbreak;
 
Reduced workforce productivity caused by, but not limited to, illness, travel
 
restrictions, quarantine,
or government mandates;
 
Business interruptions resulting from a portion of
 
our workforce continuing to telecommute,
 
as well as
the implementation and maintenance of protections
 
for employees commuting for work, such as
personnel screenings and self-quarantines before or
 
after travel;
 
and
 
Voluntary
 
or involuntary curtailments to support oil prices
 
or alleviate storage shortages for our
products.
 
Any of these factors, or other cascading effects of the
 
COVID-19 pandemic that are not currently foreseeable,
could materially increase our costs, negatively impact
 
our revenues and damage our financial condition,
 
results
of operations, cash flows and liquidity position.
 
The pandemic continues to progress and evolve,
 
and the full
extent and duration of any such impacts cannot
 
be predicted at this time because of the sweeping
 
impact of the
COVID-19 pandemic on daily life around the world.
 
We have been negatively affected and are likely to continue to be negatively affected by the recent
 
swift and
sharp drop in commodity prices.
 
The oil and gas business is fundamentally a commodity
 
business and prices for crude oil, bitumen,
 
natural gas,
NGLs and LNG can fluctuate widely depending
 
upon global events or conditions that affect supply and
demand.
 
Recently, there has been a precipitous decrease in demand for oil globally, largely caused by the
dramatic decrease in travel and commerce resulting
 
from the COVID-19 pandemic.
 
See Management’s
Discussion and Analysis of Financial Condition
 
and Results of Operations, for additional information
 
on
commodity prices and how we have been impacted.
 
There is no assurance of when or if commodity
 
prices will
return to pre-COVID-19 levels.
 
The speed and extent of any recovery remains uncertain
 
and is subject to
various risks, including the duration, impact and actions
 
taken to stem the proliferation of the COVID-19
pandemic, the extent to which those nations party
 
to the OPEC plus production agreement decide
 
to increase
production of crude oil, bitumen, natural gas and
 
NGLs and other risks described in this Quarterly
 
Report on
Form 10-Q
 
or in our Annual Report on Form 10-K for the
 
fiscal year ended December 31, 2019.
 
Even after a recovery, our industry will continue to be exposed to the effects of changing
 
commodity prices
given the volatility in commodity price drivers and
 
the worldwide political and economic
 
environment
generally, as well as continued uncertainty caused by armed hostilities
 
in various oil-producing regions around
the globe.
 
Our revenues, operating results and future rate
 
of growth are highly dependent on the prices
 
we
receive for our crude oil, bitumen, natural gas, NGLs
 
and LNG.
 
Many of the factors influencing these prices
are beyond our control.
 
 
Lower crude oil, bitumen, natural gas, NGL and LNG
 
prices may have a material adverse effect on our
revenues, earnings, cash flows and liquidity, and may also affect the amount of dividends
 
we elect to declare
and pay on our common stock.
 
As a result of the oil market downturn earlier
 
this year, we suspended our share
repurchase program.
 
Lower prices may also limit the amount of reserves
 
we can produce economically, thus
adversely affecting our proved reserves, reserve replacement
 
ratio and accelerating the reduction in our
existing reserve levels as we continue production
 
from upstream fields.
 
Prolonged lower crude oil prices may
affect certain decisions related to our operations, including
 
decisions to reduce capital investments or decisions
to shut-in production.
 
Significant reductions in crude oil, bitumen, natural
 
gas, NGLs and LNG prices could also
 
require us to reduce
our capital expenditures, impair the carrying value
 
of our assets or discontinue the classification
 
of certain
 
63
assets as proved reserves.
 
In the nine-month period of 2020, we recognized
 
several impairments, which are
described in Note 8—Impairments.
 
If the outlook for commodity prices remains
 
low relative to 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.
 
If oil and gas prices persist at depressed
levels, our reserve estimates may decrease further, which could
 
incrementally increase the rate used to
determine DD&A expense on our unit-of-production
 
method properties.
 
See Management’s Discussion and
Analysis for further examination of DD&A
 
rate impacts versus comparative periods.
 
Although it is not
reasonably practicable to quantify the impact
 
of any future impairments or estimated change to
 
our unit-of-
production at this time, our results of operations
 
could be adversely affected as a result.
 
Risks Related to the Proposed Acquisition of
 
Concho Resources Inc. (Concho)
 
 
Our ability to complete the acquisition of Concho
 
is subject to various closing conditions,
 
including
approval by our and Concho’s stockholders and regulatory clearance, which may
 
impose conditions that
could adversely affect us or cause the acquisition not to be
 
completed.
 
 
On October 18, 2020, we entered into a definitive
 
agreement (the Merger Agreement)
 
to acquire Concho, one
of the largest unconventional shale producers in the Permian
 
Basin.
 
The Merger is subject to a number of conditions to closing
 
as specified in the Merger Agreement.
 
These
closing conditions include, among others, (1) the
 
receipt of the required approvals from
 
ConocoPhillips
stockholders and Concho stockholders, (2) the expiration
 
or termination of the waiting period under the
 
Hart-
Scott-Rodino Antitrust Improvements Act of 1976,
 
as amended (the HSR Act) and (3) the
 
absence of any
governmental order or law that makes consummation
 
of the Merger illegal or otherwise prohibited.
 
No
assurance can be given that the required stockholder
 
approvals and regulatory clearance be obtained
 
or that the
required conditions to closing will be satisfied,
 
and, if all required approvals and regulatory
 
clearance are
obtained and the required conditions are satisfied,
 
no assurance can be given as to the terms,
 
conditions and
timing of such approvals and clearance,
 
including whether any required conditions
 
will materially adversely
affect the combined company following the acquisition.
 
Any delay in completing the Merger could cause the
combined company not to realize, or to be delayed
 
in realizing, some or all of the benefits
 
that we and Concho
expect to achieve if the Merger is successfully completed
 
within its expected time frame.
 
We can provide no assurance that these conditions will not result in the abandonment
 
or delay of the
acquisition.
 
The occurrence of any of these events individually
 
or in combination could have a material
adverse effect on our results of operations and the trading
 
price of our common stock.
 
The termination of the Merger Agreement could
 
negatively impact our business or result
 
in our having to
pay a termination fee.
 
If the Merger is not completed for any reason, including
 
as a result of a failure to obtain the required approvals
from our stockholders or Concho’s stockholders, our ongoing business may
 
be adversely affected and, without
realizing any of the expected benefits of having completed
 
the Merger, we would be subject to a number of
risks, including the following:
 
 
 
we may experience negative reactions from the
 
financial markets, including negative impacts
 
on our
 
stock price;
 
we may experience negative reactions from our commercial
 
and vendor partners and employees; and
 
we will be required to pay our costs relating to
 
the Merger, such as financial advisory, legal, financing
and accounting costs and associated fees and expenses,
 
whether or not the Merger is completed.
 
Additionally, if the Merger Agreement is terminated under certain circumstances, we
 
may be required
 
to pay a termination fee of $450 million, including
 
if the proposed Merger is terminated because our Board
 
of
 
Directors has changed its recommendation in respect
 
of the stockholder proposal relating to the Merger.
 
In
 
 
64
addition, we may be required to reimburse Concho
 
for its expenses in an amount equal
 
to $142.5 million, if the
 
Merger Agreement is terminated because of a failure of our
 
stockholders to approve the stockholder proposal.
 
 
Whether or not the Merger is completed, the announcement
 
and pendency of the Merger could cause
disruptions in our business, which could have an
 
adverse effect on our business and financial results.
 
Whether or not the Merger is completed, the announcement
 
and pendency of the Merger could cause
disruptions in our business.
 
Specifically:
 
 
our and Concho’s current and prospective employees will experience uncertainty
 
about their future
roles with the combined company, which might adversely affect the two companies’ abilities
 
to retain
key managers and other employees;
 
uncertainty regarding the completion of the Merger may
 
cause our and Concho’s commercial and
vendor partners or others that deal with us or Concho
 
to delay or defer certain business decisions
 
or to
decide to seek to terminate, change or renegotiate
 
their relationships with us or Concho, which
 
could
negatively affect our respective revenues, earnings and cash
 
flows;
 
the Merger Agreement restricts us and our subsidiaries
 
from taking specified actions during the
pendency of the Merger without Concho’s consent,
 
which may prevent us from making appropriate
changes to our business or organizational structure
 
or prevent us from pursuing attractive business
opportunities or strategic transactions that may
 
arise prior to the completion of the Merger; and
 
the attention of our and Concho’s management may be directed toward
 
the completion of the Merger,
as well as integration planning, which could otherwise
 
have been devoted to day-to-day operations or
to other opportunities that may have been beneficial
 
to our business.
 
We have and will continue to divert significant management resources in an effort to complete
 
the Merger and
are subject to restrictions contained in the Merger Agreement
 
on the conduct of our business.
 
If the Merger is
not completed, we will have incurred significant
 
costs, including the diversion of management resources,
 
for
which we will have received little or no benefit.
 
The market value of our common stock could
 
decline if large amounts of our common
 
stock are sold
following the Concho acquisition.
 
If the Merger is consummated, ConocoPhillips will
 
issue shares of ConocoPhillips common stock
 
to former
Concho stockholders.
 
Former Concho stockholders may decide not to
 
hold the shares of ConocoPhillips
common stock that they will receive in the Merger, and ConocoPhillips
 
stockholders may decide to reduce
their investment in ConocoPhillips as a result
 
of the changes to ConocoPhillips’ investment
 
profile as a result
of the Merger.
 
Other Concho stockholders, such as funds
 
with limitations on their permitted holdings of
 
stock
in individual issuers, may be required to sell the
 
shares of ConocoPhillips common stock that
 
they receive in
the Merger.
 
Such sales of ConocoPhillips common stock
 
could have the effect of depressing the market price
for ConocoPhillips common stock.
 
Combining our business with Concho’s may be more difficult, costly or time-consuming
 
than expected and
the combined company may fail to realize
 
the anticipated benefits of the Merger, which may adversely affect
the combined company’s business results and negatively affect the value of the combined
 
company’s
common stock.
 
 
The success of the Merger will depend on, among other
 
things, the ability of the two companies to combine
their businesses in a manner that facilitates
 
growth opportunities and realizes expected cost
 
savings.
 
The
combined company may encounter difficulties in integrating
 
our and Concho’s businesses and realizing the
anticipated benefits of the Merger.
 
The combined company must achieve the
 
anticipated improvement in free
cash flow generation and returns and achieve the
 
planned cost savings without adversely affecting current
revenues or compromising the disciplined investment
 
philosophy for future growth.
 
If the combined company
is not able to successfully achieve these objectives,
 
the anticipated benefits of the Merger may not be
 
realized
fully, or at all, or may take longer to realize than expected.
 
 
 
 
 
 
 
 
 
 
65
 
The Merger involves the combination of two companies
 
which currently operate, and until the completion
 
of
the Merger will continue to operate, as independent public
 
companies.
 
There can be no assurances that our
respective businesses can be integrated successfully.
 
It is possible that the integration process could result
 
in
the loss of key employees from both companies;
 
the loss of commercial and vendor partners;
 
the disruption of
our, Concho’s or both companies’ ongoing businesses;
 
inconsistencies in standards, controls, procedures
 
and
policies;
 
unexpected integration issues;
 
higher than expected integration costs and an overall
 
post-completion
integration process that takes longer than originally
 
anticipated.
 
The combined company will be required
 
to
devote management attention and resources to integrating
 
its business practices and operations, and prior
 
to the
Merger, management attention and resources will be required to plan for
 
such integration.
 
An inability to realize the full extent of the anticipated
 
benefits of the Merger and the other transactions
contemplated by the Merger Agreement, as well as any delays
 
encountered in the integration process, could
have an adverse effect upon the revenues, level of expenses
 
and operating results of the combined company,
which may adversely affect the value of the common stock
 
of the combined company.
 
 
In addition, the actual integration may result
 
in additional and unforeseen expenses, and the
 
anticipated
benefits of the integration plan may not be realized.
 
There are a large number of processes, policies,
procedures, operations and technologies and systems
 
that must be integrated in connection with
 
the Merger
and the integration of Concho’s business.
 
Although we expect that the elimination of duplicative
 
costs,
strategic benefits, and additional income, as well
 
as the realization of other efficiencies related to the
integration of the business, may offset incremental transaction
 
and Merger-related costs over time, any net
benefit may not be achieved in the near term
 
or at all.
 
If we and Concho are not able to adequately
 
address
integration challenges, we may be unable to successfully
 
integrate operations or realize the anticipated
 
benefits
of the integration of the two companies.
 
Item 2.
 
UNREGISTERED SALES OF EQUITY SECURITIES
 
AND USE OF PROCEEDS
 
Issuer Purchases of Equity Securities
Millions of Dollars
Period
Total Number of
Shares
Purchased
*
Average Price
Paid per Share
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
Approximate Dollar
Value
 
of Shares That
May Yet Be
Purchased Under the
Plans or Programs
July 1-31, 2020
-
$
-
-
$
14,649
August 1-31, 2020
-
-
-
14,649
September 1-30, 2020
-
-
-
14,649
-
$
-
-
*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.
 
In late 2016, we initiated our current share repurchase
 
program.
 
As of September 30, 2020, we had announced
a total authorization to repurchase $25 billion
 
of our common stock.
 
As of December 31, 2019, we had
repurchased $9.6 billion of shares.
 
In the first quarter of 2020, we repurchased
 
an additional $726 million of
shares.
 
On April 16, 2020, as a response to the oil market
 
downturn, we announced we were suspending our
share repurchase program,
 
and on September 30, 2020, we announced our
 
intent to resume share repurchases
of $1 billion in the fourth quarter;
 
however, on October 19, 2020 we announced that we had entered
 
into a
definitive agreement to acquire Concho and would
 
suspend share repurchases until after
 
the transaction closes.
 
The transaction is expected to close in the first
 
quarter of 2021.
 
Acquisitions for the share repurchase program
are made at management’s discretion, at prevailing prices, subject to market
 
conditions and other factors.
 
Except as limited by applicable legal requirements,
 
repurchases may be increased, decreased or discontinued
 
at
any time without prior notice.
 
Shares of stock repurchased under the plan are
 
held as treasury shares.
 
See the
“Our ability to declare and pay dividends and repurchase
 
shares is subject to certain considerations” section
 
in
Risk Factors on pages 21–22 of our 2019 Annual
 
Report on Form 10-K.
 
 
67
SIGNATURE
 
 
Pursuant to the requirements of the Securities Exchange
 
Act of 1934, the registrant has duly caused this report
to be signed on its behalf by the undersigned thereunto
 
duly authorized.
 
 
CONOCOPHILLIPS
/s/ Catherine A. Brooks
Catherine A. Brooks
Vice President and Controller
(Chief Accounting and Duly Authorized Officer)
 
November 3, 2020