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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
Page
Commonly Used Abbreviations
………………………………………………………………………...
1
Part I—Financial Information
Item 1. Financial Statements
Consolidated Income Statement
……………………………………………………………………..
.
2
Consolidated Statement of Comprehensive Income
…………………………………………………
.
3
Consolidated Balance Sheet
…………………………………………………………………………
.
4
Consolidated Statement of Cash Flows
……………………………………………………………...
.
5
Notes to Consolidated Financial Statements
………………………………………………………...
.
6
Item 2. Management’s Discussion and Analysis of Financial Condition and
Results of Operations
…………………………………………………………………………
.
32
Item 3. Quantitative and Qualitative Disclosures About Market Risk
………………………………..
..
59
Item 4. Controls and Procedures
………………………………………………………………………
.
60
Part II—Other Information
Item 1. Legal Proceedings
……………………………………………………………………………..
.
60
Item 1A. Risk Factors
…………………………………………………………………………………
.
60
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
………………………………...
.
65
Item 6. Exhibits
………………………………………………………………………………………..
.
66
Signature
………………………………………………………………………………………………….
.
67
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.
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.
66
Item 6.
EXHIBITS
2.1
Agreement and Plan of Merger, dated as of October 18, 2020, among ConocoPhillips, Falcon
Merger Sub Corp. and Concho Resources Inc. (incorporated by reference to Exhibit 2.1 to the
Current Report of ConocoPhillips on Form 8-K filed on October 19, 2020; File No. 001-32395)
10.1*
Successor Trustee Agreement of the Deferred Compensation Trust Agreement for Non-
Employee Directors of ConocoPhillips, dated July 31, 2020.
10.2*
First Amendment to the Successor Trustee Agreement of the Deferred Compensation Trust
Agreement for Non-Employee Directors of ConocoPhillips, dated August 4, 2020.
22*
Subsidiary Guarantors of Guaranteed Securities.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934.
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934.
32*
Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*
Inline XBRL Instance Document.
101.SCH*
Inline XBRL Schema Document.
101.CAL*
Inline XBRL Calculation Linkbase Document.
101.LAB*
Inline XBRL Labels Linkbase Document.
101.PRE*
Inline XBRL Presentation Linkbase Document.
101.DEF*
Inline XBRL Definition Linkbase Document.
104*
Cover Page Interactive Data File (formatted
as Inline XBRL and contained in Exhibit 101).
* Filed herewith.
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