UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM
10-Q

(Mark One)

☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

[
X
]
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September
June 30, 2017

2021

or

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

[ ]
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)

Delaware01-0562944

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

600 North Dairy Ashford,

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
(Zip Code)

281-293-1000

281
-
293-1000
(Registrant’sRegistrant'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 filesubmit such reports), and (2) has been subject to such filing requirements for the past 90 days.    files).
Yes  ☒
[x] No ☐

[

]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of RegulationS-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant

is a large accelerated filer, an accelerated filer, anon-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
Rule12b-2 of the
Exchange Act.

Large accelerated filer☒Accelerated filer☐
Non-accelerated filer☐Smaller reporting company☐
Emerging growth company☐

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 Rule12b-2 of the
Exchange
Act).
Yes  ☐    
[
]
No  ☒

[x]
The registrant had 1,195,515,824
1,339,082,083
shares of common stock, $.01 par value,
outstanding at SeptemberJune 30, 2017.

2021.

CONOCOPHILLIPS

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1
Commonly Used Abbreviations
The following industry-specific, accounting and
other terms, and abbreviations may be commonly
used in this
report.
Currencies
Accounting
$ or USD
U.S. dollar
ARO
asset retirement obligation
CAD
Canadian dollar
ASC
accounting standards codification
EUR
Euro
ASU
accounting standards update
GBP
British pound
DD&A
depreciation, depletion and
amortization
Units of Measurement
FASB
Financial Accounting Standards
BBL
barrel
Board
BCF
billion cubic feet
FIFO
first-in, first-out
BOE
barrels of oil equivalent
G&A
general and administrative
MBD
thousands of barrels per day
GAAP
generally accepted accounting
MCF
thousand cubic feet
principles
MBOD
thousand barrels of oil per day
LIFO
last-in, first-out
MM
million
NPNS
normal purchase normal sale
MMBOE
million barrels of oil equivalent
PP&E
properties, plants and equipment
MMBOD
million barrels of oil per day
SAB
staff accounting bulletin
MBOED
thousands of barrels of oil
VIE
variable interest entity
MMBOED
equivalent per day
millions of barrels of oil
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
G&G
geological and geophysical
ICSID
World Bank’s
International
JOA
joint operating agreement
Centre for Settlement of
LNG
liquefied natural gas
Investment Disputes
NGLs
natural gas liquids
IRS
Internal Revenue Service
OPEC
Organization of Petroleum
OTC
over-the-counter
Exporting Countries
NYSE
New York Stock Exchange
PSC
production sharing contract
SEC
U.S. Securities and Exchange
PUDs
proved undeveloped reserves
Commission
SAGD
steam-assisted gravity drainage
TSR
total shareholder return
WCS
Western Canada Select
U.K.
United Kingdom
WTI
West Texas
Intermediate
U.S.
United States of America
2
PART
I.
FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS

Consolidated Income StatementConocoPhillips

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Revenues and Other Income

     

Sales and other operating revenues

  $6,688   6,415   20,987   16,884 

Equity in earnings (losses) of affiliates

   196   (60)   574   (129) 

Gain on dispositions

   246   51   2,144   202 

Other income

   65   110   143   149 

 

 

Total Revenues and Other Income

   7,195   6,516   23,848   17,106 

 

 

Costs and Expenses

     

Purchased commodities

   2,926   2,819   9,040   7,046 

Production and operating expenses

   1,224   1,526   3,849   4,325 

Selling, general and administrative expenses

   132   203   423   556 

Exploration expenses

   75   457   724   1,572 

Depreciation, depletion and amortization

   1,608   2,425   5,212   7,001 

Impairments

   6   123   6,475   321 

Taxes other than income taxes

   175   161   604   538 

Accretion on discounted liabilities

   89   108   276   329 

Interest and debt expense

   251   335   872   928 

Foreign currency transaction losses

   5   13   28   12 

Other expense

   51   —   285   — 

 

 

Total Costs and Expenses

   6,542   8,170   27,788   22,628 

 

 

Income (loss) before income taxes

   653   (1,654)   (3,940)   (5,522) 

Income tax provision (benefit)

   217   (628)   (1,549)   (1,982) 

 

 

Net Income (Loss)

   436   (1,026)   (2,391)   (3,540) 

Less: net income attributable to noncontrolling interests

   (16)   (14)   (43)   (40) 

 

 

Net Income (Loss) Attributable to ConocoPhillips

  $420   (1,040)   (2,434)   (3,580) 

 

 

Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock(dollars)

     

Basic

  $0.35   (0.84)   (1.98)   (2.88) 

Diluted

   0.34   (0.84)   (1.98)   (2.88) 

 

 

Dividends Paid Per Share of Common Stock(dollars)

  $0.27   0.25   0.80   0.75 

 

 

Average Common Shares Outstanding(in thousands)

     

Basic

   1,212,454   1,245,961   1,230,742   1,245,139 

Diluted

   1,215,341   1,245,961   1,230,742   1,245,139 

 

 

Item 1.
FINANCIAL STATEMENTS
Consolidated Income Statement
ConocoPhillips
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Revenues and Other Income
Sales and other operating revenues
$
9,556
2,749
19,382
8,907
Equity in earnings of affiliates
139
77
261
311
Gain on dispositions
59
596
292
554
Other income (loss)
457
594
835
(945)
Total Revenues and
Other Income
10,211
4,016
20,770
8,827
Costs and Expenses
Purchased commodities
2,998
1,130
7,481
3,791
Production and operating expenses
1,379
1,047
2,762
2,220
Selling, general and administrative expenses
117
156
428
153
Exploration expenses
57
97
141
285
Depreciation, depletion and amortization
1,867
1,158
3,753
2,569
Impairments
2
(2)
(1)
519
Taxes other than income
taxes
381
141
751
391
Accretion on discounted liabilities
63
66
125
133
Interest and debt expense
220
202
446
404
Foreign currency transaction (gain) loss
10
7
29
(83)
Other expenses
37
(7)
61
(13)
Total Costs and Expenses
7,131
3,995
15,976
10,369
Income (loss) before income taxes
3,080
21
4,794
(1,542)
Income tax provision (benefit)
989
(257)
1,721
(109)
Net income (loss)
2,091
278
3,073
(1,433)
Less: net income attributable to noncontrolling interests
0
(18)
0
(46)
Net Income (Loss) Attributable to ConocoPhillips
$
2,091
260
3,073
(1,479)
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
1.55
0.24
2.32
(1.37)
Diluted
1.55
0.24
2.31
(1.37)
Average Common
Shares Outstanding
(in thousands)
Basic
1,348,637
1,076,659
1,324,639
1,080,610
Diluted
1,353,201
1,077,606
1,329,507
1,080,610
See Notes to Consolidated Financial Statements.

Consolidated Statement of Comprehensive IncomeConocoPhillips

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Net Income (Loss)

  $436   (1,026)   (2,391)   (3,540) 

Other comprehensive income (loss)

     

Defined benefit plans

     

Reclassification adjustment for amortization of prior service credit included in net income

   (9)   (7)   (28)   (25) 

Net actuarial gain (loss) arising during the period

   13   (31)   (26)   (331) 

Reclassification adjustment for amortization of net actuarial losses included in net income

   49   47   205   229 

Nonsponsored plans*

   —   2   —   2 

Income taxes on defined benefit plans

   (18)   (2)   (52)   51 

 

 

Defined benefit plans, net of tax

   35   9   99   (74) 

 

 

Unrealized holding gain on securities

   551   —   127   — 

Income taxes on unrealized holding gain on securities

   (45)   —   (45)   — 

 

 

Unrealized gain on securities, net of tax

   506   —   82   — 

 

 

Foreign currency translation adjustments

   509   (82)   720   877 

 

 

Foreign currency translation adjustments, net of tax

   509   (82)   720   877 

 

 

Other Comprehensive Income (Loss), Net of Tax

   1,050   (73)   901   803 

 

 

Comprehensive Income (Loss)

   1,486   (1,099)   (1,490)   (2,737) 

Less: comprehensive income attributable to noncontrolling interests

   (16)   (14)   (43)   (40) 

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

  $1,470   (1,113)   (1,533)   (2,777) 

 

 

*Plans

3
Consolidated Statement of Comprehensive Income
ConocoPhillips
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Net Income (Loss)
$
2,091
278
3,073
(1,433)
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for which ConocoPhillips is notamortization of prior
service credit included in net income (loss)
(10)
(8)
(19)
(16)
Net actuarial gain arising during the primary obligor-primarily those administered by equity affiliates.

period

30
0
105
5
Reclassification adjustment for amortization of net actuarial
losses included in net income (loss)
63
18
88
36
Income taxes on defined benefit plans
(19)
(3)
(40)
(7)
Defined benefit plans, net of tax
64
7
134
18
Unrealized holding gain (loss) on securities
0
6
(1)
3
Income taxes on unrealized holding gain on securities
0
(2)
0
(1)
Unrealized holding gain (loss) on securities, net of tax
0
4
(1)
2
Foreign currency translation adjustments
96
309
165
(490)
Income taxes on foreign currency translation adjustments
0
0
0
2
Foreign currency translation adjustments, net of tax
96
309
165
(488)
Other Comprehensive Income (Loss), Net of
Tax
160
320
298
(468)
Comprehensive Income (Loss)
2,251
598
3,371
(1,901)
Less: comprehensive income attributable to noncontrolling interests
0
(18)
0
(46)
Comprehensive Income (Loss) Attributable to
ConocoPhillips
$
2,251
580
3,371
(1,947)
See Notes to Consolidated Financial Statements.

Consolidated Balance SheetConocoPhillips

                            
   Millions of Dollars 
   September 30
2017		  December 31
2016		 
  

 

 

 

Assets

   

Cash and cash equivalents

  $6,911   3,610 

Short-term investments

   2,696   50 

Accounts and notes receivable (net of allowance of $4 million in 2017 and $5 million in 2016)

   3,222   3,249 

Accounts and notes receivable—related parties

   142   165 

Investment in Cenovus Energy

   2,084   — 

Inventories

   1,023   1,018 

Prepaid expenses and other current assets

   876   517 

 

 

Total Current Assets

   16,954   8,609 

Investments and long-term receivables

   9,696   21,091 

Loans and advances—related parties

   461   581 

Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $64,115 million in 2017 and $73,075 million in 2016)

   46,669   58,331 

Other assets

   1,081   1,160 

 

 

Total Assets

  $74,861   89,772 

 

 

Liabilities

   

Accounts payable

  $3,378   3,631 

Accounts payable—related parties

   38   22 

Short-term debt

   1,331   1,089 

Accrued income and other taxes

   1,005   484 

Employee benefit obligations

   528   689 

Other accruals

   851   994 

 

 

Total Current Liabilities

   7,131   6,909 

Long-term debt

   19,673   26,186 

Asset retirement obligations and accrued environmental costs

   7,763   8,425 

Deferred income taxes

   6,262   8,949 

Employee benefit obligations

   1,903   2,552 

Other liabilities and deferred credits

   1,417   1,525 

 

 

Total Liabilities

   44,149   54,546 

 

 

Equity

   

Common stock (2,500,000,000 shares authorized at $.01 par value)

   

Issued (2017—1,785,195,738 shares; 2016—1,782,079,107 shares)

   

Par value

   18   18 

Capital in excess of par

   46,595   46,507 

Treasury stock (at cost: 2017—589,679,914 shares; 2016—544,809,771 shares)

   (38,951)   (36,906) 

Accumulated other comprehensive loss

   (5,292)   (6,193) 

Retained earnings

   28,130   31,548 

 

 

Total Common Stockholders’ Equity

   30,500   34,974 

Noncontrolling interests

   212   252 

 

 

Total Equity

   30,712   35,226 

 

 

Total Liabilities and Equity

  $74,861   89,772 

 

 

4
Consolidated Balance Sheet
ConocoPhillips
Millions of Dollars
June 30
December 31
2021
2020
Assets
Cash and cash equivalents
$
6,608
2,991
Short-term investments
2,251
3,609
Accounts and notes receivable (net of allowance of $
2
and $
4
, respectively)
4,401
2,634
Accounts and notes receivable—related parties
123
120
Investment in Cenovus Energy
1,802
1,256
Inventories
1,138
1,002
Prepaid expenses and other current assets
849
454
Total Current Assets
17,172
12,066
Investments and long-term receivables
8,013
8,017
Loans and advances—related parties
59
114
Net properties, plants and equipment
(net of accumulated DD&A of $
65,572
and $
62,213
, respectively)
57,717
39,893
Other assets
2,442
2,528
Total Assets
$
85,403
62,618
Liabilities
Accounts payable
$
3,591
2,669
Accounts payable—related parties
22
29
Short-term debt
1,205
619
Accrued income and other taxes
1,406
320
Employee benefit obligations
571
608
Other accruals
1,355
1,121
Total Current Liabilities
8,150
5,366
Long-term debt
18,805
14,750
Asset retirement obligations and accrued environmental costs
5,819
5,430
Deferred income taxes
5,331
3,747
Employee benefit obligations
1,297
1,697
Other liabilities and deferred credits
1,725
1,779
Total Liabilities
41,127
32,769
Equity
Common stock (
2,500,000,000
shares authorized at $
0.01
par value)
Issued (2021—
2,087,542,804
shares; 2020—
1,798,844,267
shares)
Par value
21
18
Capital in excess of par
60,337
47,133
Treasury stock (at cost: 2021—
748,460,721
shares; 2020—
730,802,089
shares)
(48,278)
(47,297)
Accumulated other comprehensive loss
(4,920)
(5,218)
Retained earnings
37,116
35,213
Total Equity
44,276
29,849
Total Liabilities and Equity
$
85,403
62,618
See Notes to Consolidated Financial Statements.

Consolidated Statement of Cash FlowsConocoPhillips

                            
   Millions of Dollars 
   Nine Months Ended
September 30		 
   2017   2016 
  

 

 

 

Cash Flows From Operating Activities

   

Net loss

  $(2,391)   (3,540) 

Adjustments to reconcile net loss to net cash provided by operating activities

   

Depreciation, depletion and amortization

   5,212   7,001 

Impairments

   6,475   321 

Dry hole costs and leasehold impairments

   435   1,010 

Accretion on discounted liabilities

   276   329 

Deferred taxes

   (2,770)   (2,152) 

Distributions received greater than equity losses (undistributed equity earnings)

   (193)   414 

Gain on dispositions

   (2,144)   (202) 

Other

   (367)   (50) 

Working capital adjustments

   

Decrease in accounts and notes receivable

   65   1,112 

Decrease (increase) in inventories

   (15)   22 

Decrease (increase) in prepaid expenses and other current assets

   (12)   46 

Decrease in accounts payable

   (212)   (515) 

Increase (decrease) in taxes and other accruals

   237   (836) 

 

 

Net Cash Provided by Operating Activities

   4,596   2,960 

 

 

Cash Flows From Investing Activities

   

Capital expenditures and investments

   (3,074)   (3,870) 

Working capital changes associated with investing activities

   (18)   (401) 

Proceeds from asset dispositions

   13,740   419 

Net purchases of short-term investments

   (2,583)   (229) 

Collection of advances/loans—related parties

   115   108 

Other

   51   61 

 

 

Net Cash Provided by (Used in) Investing Activities

   8,231   (3,912) 

 

 

Cash Flows From Financing Activities

   

Issuance of debt

   —   4,594 

Repayment of debt

   (6,594)   (839) 

Issuance of company common stock

   (65)   (52) 

Repurchase of company common stock

   (2,045)   — 

Dividends paid

   (986)   (940) 

Other

   (80)   (93) 

 

 

Net Cash Provided by (Used in) Financing Activities

   (9,770)   2,670 

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

   244   4 

 

 

Net Change in Cash and Cash Equivalents

   3,301   1,722 

Cash and cash equivalents at beginning of period

   3,610   2,368 

 

 

Cash and Cash Equivalents at End of Period

  $6,911   4,090 

 

 

5
Consolidated Statement of Cash Flows
ConocoPhillips
Millions of Dollars
Six Months Ended
June 30
2021
2020
Cash Flows From Operating Activities
Net income (loss)
$
3,073
(1,433)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities
Depreciation, depletion and amortization
3,753
2,569
Impairments
(1)
519
Dry hole costs and leasehold impairments
7
70
Accretion on discounted liabilities
125
133
Deferred taxes
567
(320)
Undistributed equity earnings
317
404
Gain on dispositions
(292)
(554)
(Gain) loss on investment in Cenovus Energy
(726)
1,140
Other
(688)
(244)
Working
capital adjustments
Decrease (increase) in accounts and notes receivable
(794)
1,746
Increase in inventories
(89)
(27)
Increase in prepaid expenses and other current assets
(388)
(149)
Increase (decrease) in accounts payable
323
(754)
Increase (decrease) in taxes and other accruals
1,144
(838)
Net Cash Provided by Operating Activities
6,331
2,262
Cash Flows From Investing Activities
Cash acquired from Concho
382
0
Capital expenditures and investments
(2,465)
(2,525)
Working
capital changes associated with investing activities
2
(251)
Proceeds from asset dispositions
160
1,313
Net sales (purchases) of investments
1,302
(1,030)
Collection of advances/loans—related parties
52
66
Other
86
(35)
Net Cash Used in Investing Activities
(481)
(2,462)
Cash Flows From Financing Activities
Repayment of debt
(44)
(214)
Issuance of company common stock
(25)
2
Repurchase of company common stock
(981)
(726)
Dividends paid
(1,171)
(913)
Other
3
(28)
Net Cash Used in Financing Activities
(2,218)
(1,879)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash
9
(93)
Net Change in Cash, Cash Equivalents and Restricted Cash
3,641
(2,172)
Cash, cash equivalents and restricted cash at beginning of period
3,315
5,362
Cash, Cash Equivalents and Restricted Cash at End of Period
$
6,956
3,190
Restricted cash of $
95
million and $
253
million are included in the "Prepaid expenses and other current assets" and "Other assets" lines,
respectively, of our Consolidated Balance Sheet as of June 30, 2021.
Restricted cash of $
94
million and $
230
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, 2020.
See Notes to Consolidated Financial Statements.

Notes to Consolidated Financial StatementsConocoPhillips

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 20162020 Annual Report on Form
10-K.

Note 2—Variable Interest Entities (VIEs)

We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant VIEs follows:

Australia Pacific LNG Pty Ltd (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as liquefied natural gas (LNG) processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method investment.

As of September 30, 2017, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 5—Investments, Loans and Long-Term Receivables, and Note 11—Guarantees, for additional information.

Marine Well Containment Company, LLC (MWCC)

MWCC provides well containment equipment and technology and related services in the deepwater U.S. Gulf of Mexico. Its principal activities involve the development and maintenance of rapid-response hydrocarbon well containment systems that are deployable in the Gulf of Mexico on acall-out basis. We have a 10 percent ownership interest in MWCC, and it is accounted for as an equity method investment because MWCC is a limited liability company in which we are a Founding Member and exercise significant influence through our permanent seat on theten-member Executive Committee responsible for overseeing the affairs of MWCC. In 2016, MWCC executed a $154 million term loan financing arrangement with an external financial institution whose terms required the financing be secured by letters of credit provided by certain owners of MWCC, including ConocoPhillips. In connection with the financing transaction, we issued a letter of credit of $22 million which can be drawn upon in the event of a default by MWCC on its obligation to repay the proceeds of the term loan. The fair value of this letter of credit is immaterial and not recognized on our consolidated balance sheet. MWCC is considered a VIE, as it has entered into arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary and do not consolidate MWCC because we share the power to govern the business and operation of the company and to undertake certain obligations that most significantly impact its economic performance with nine other unaffiliated owners of MWCC.

At September 30, 2017, the carrying value of our equity method investment in MWCC was $141 million. We have not provided any financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of MWCC.

Note 3—Inventories

Inventories consisted of the following:

                            
   Millions of Dollars 
   September 30
2017		   December 31
2016		 
  

 

 

 

Crude oil and natural gas

  $465    418 

Materials and supplies

   558    600 

 

 
  $1,023    1,018 

 

 

Millions of Dollars
June 30
December 31
2021
2020
Crude oil and natural gas
$
572
461
Materials and supplies
566
541
$
1,138
1,002
Inventories valued on thelast-in,first-out (LIFO) LIFO basis totaled $297 
$
348
million and $269 $
282
million at SeptemberJune 30, 20172021 and December
31, 2016,2020, respectively.
Note 3—Acquisitions and Dispositions
Acquisition of
Concho Resources Inc.
(Concho)
We completed our acquisition of Concho on
January 15, 2021
and as defined under the terms of the
transaction
agreement, each share of Concho common stock
was exchanged for
1.46
shares of ConocoPhillips common
stock, for total consideration of $
13.1
billion.
Total Consideration
Number of shares of Concho common stock
issued and outstanding (in thousands)*
194,243
Number of shares of Concho stock awards outstanding
(in thousands)*
1,599
Number of shares exchanged
195,842
Exchange ratio
1.46
Additional shares of ConocoPhillips common stock
issued as consideration (in thousands)
285,929
Average price per share of ConocoPhillips common stock**
$
45.9025
Total Consideration (Millions)
$
13,125
*Outstanding as of January 15, 2021.
**Based on the ConocoPhillips average stock price on January
15, 2021.
7
The estimated excesstransaction was accounted for as a business
combination under FASB ASC 805 using the acquisition
method, which requires assets acquired and liabilities
assumed to be measured at their acquisition date fair
values.
Fair value measurements were made for acquired
assets and liabilities, and adjustments to those
measurements may be made in subsequent periods,
up to one year from the acquisition date as
we identify new
information about facts and circumstances that existed
as of current replacementthe acquisition date to consider.
Oil and gas
properties were valued using a discounted cash
flow approach incorporating market participant
and internally
generated price assumptions;
production profiles;
and operating and development cost over LIFO cost of inventories was approximately $90 million and $104 million at September 30, 2017 and December 31, 2016, respectively.

Note 4—Assets Held for Sale or Sold

Assets Held for Sale

On June 28, 2017, we signed a definitive agreement with an affiliate of Miller Thomson & Partners LLC to sell our interestsassumptions.

Debt
assumed in the Barnettacquisition was valued based on
observable market prices.
The fair values determined for $305 million in cash, subject
accounts receivables, accounts payable, and most
other current assets and current liabilities
were equivalent to customary adjustments. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the fourth quarter of 2017. We recorded abefore-tax impairment of $566 million in the second quarter of 2017 to reduce
the carrying value due to their short-term
nature.
The total consideration of our investment$
13.1
billion was allocated to the
identifiable assets and liabilities based on their
fair valuevalues as of January 15, 2021.
Assets Acquired
Millions of Dollars
Cash and an additional impairment of $2 million was recorded in the third quarter of 2017. As of September 30, 2017, our Barnett interests had acash equivalents
$
382
Accounts receivable, net carrying value of approximately $296 million and were considered held for sale resulting in the reclassification of $344 million of properties, plants and equipment (PP&E) to “Prepaid
742
Inventories
45
Prepaid expenses and other current assets”assets
37
Investments and $49 long-term receivables
333
Net properties, plants and equipment
18,971
Other assets
62
Total assets acquired
$
20,572
Liabilities Assumed
Accounts payable
$
638
Accrued income and other taxes
49
Employee benefit obligations
4
Other accruals
510
Long-term debt
4,696
Asset retirement obligations and accrued environmental
costs
310
Deferred income taxes
1,123
Other liabilities and deferred credits
117
Total liabilities assumed
$
7,447
Net assets acquired
$
13,125
With the completion of the Concho transaction, we acquired proved
and unproved properties of approximately
$
11.8
billion and $
6.9
billion, respectively.
We recognized approximately $
157
million of noncurrent liabilities,transaction-related costs that
were expensed in the first quarter
of 2021.
These non-recurring costs related primarily asset retirement obligations,
to “Other accruals”fees paid to advisors and the settlement of
share-based
awards for certain Concho employees based
on the terms of the Merger Agreement.
In the first quarter of 2021, we commenced a restructuring
program,
the scope of which included combining
the operations of the two companies.
For the three-
and six-month periods ending June 30, 2021,
we
recognized non-recurring restructuring costs mainly
for employee severance and related incremental pension
benefit costs of approximately $
23
million and $
157
million, respectively.
8
The impact from these transaction and restructuring
costs to the lines of our consolidated income statement
for
the six-month period ending June 30, 2021, are below:
Millions of Dollars
Transaction Cost
Restructuring Cost
Total Cost
Production and operating expenses
$
70
70
Selling, general and administration expenses
135
52
187
Exploration expenses
18
4
22
Taxes other than income taxes
4
2
6
Other expenses
0
29
29
$
157
157
314
On February 8, 2021, we completed a debt exchange
offer related to the debt assumed from Concho.
As a
result of the debt exchange, we recognized an additional
income tax related restructuring charge of $
75
million.
From the acquisition date through June 30, 2021,
“Total Revenues and Other Income” and “Net Income (Loss)
Attributable to ConocoPhillips” associated with the
acquired Concho business were approximately
$
2,637
million and $
828
million, respectively.
The results associated with the Concho business
include a before- and
after-tax loss of $
305
million and $
233
million, respectively, on the acquired derivative contracts.
The before-
tax loss is recorded within “Total Revenues and Other Income” on our consolidated balance sheet.
income statement.
Thebefore-tax following summarizes the unaudited supplemental
pro forma financial information as if we had completed
the acquisition of Concho on January 1, 2020:
Millions of Dollars
Supplemental Pro Forma (unaudited)
Three Months Ended
June 30, 2020
Six Months Ended
June 30, 2020
Total revenues and other income
$
4,065
11,365
Net loss
(229)
(619)
Net loss associatedattributable to ConocoPhillips
(247)
(665)
$ per share
Earnings per share:
Three Months Ended
June 30, 2020
Six Months Ended
June 30, 2020
Basic net loss
$
(0.18)
(0.49)
Diluted net loss
(0.18)
(0.49)
The unaudited supplemental pro forma financial
information is presented for illustration purposes
only and is
not necessarily indicative of the operating results
that would have occurred had the transaction been
completed
on January 1, 2020, nor is it necessarily indicative
of future operating results of the combined entity.
The
unaudited pro forma financial information
for the three-
and six-month periods ending June 30, 2020 is a result
of combining the consolidated income statement
of ConocoPhillips with our intereststhe results of Concho.
The pro forma
results do not include transaction-related costs,
nor any cost savings anticipated as a result
of the transaction.
The pro forma results include adjustments to
reverse impairment expense of $
10.5
billion and $
1.9
billion
recorded by Concho in the Barnett, includingsix-month period ending
June 30, 2020, related to oil and gas properties
and
goodwill, respectively.
Other adjustments made relate primarily to
DD&A, which is based on the $566 unit-of-
production method, resulting from the purchase
price allocated to properties, plants and equipment.
We
believe the estimates and assumptions are reasonable,
and the relative effects of the transaction are properly
reflected.
9
Assets Sold
In 2020, we completed the sale of our Australia-West asset and operations.
The sales agreement entitled us to
a $
200
million payment upon a final investment
decision (FID) of the Barossa development
project.
On March
30, 2021, FID was announced and $2 as such,
we recognized a $
200
million impairments noted above, was $575 gain on disposition in the first
quarter
of 2021.
The purchaser failed to pay the FID bonus when
due.
We have commenced an arbitration proceeding
against the purchaser to enforce our contractual right
to the $
200
million, and $55 million forplus interest accruing from the nine-month periods ended September 30, 2017 and September 30, 2016, respectively. The Barnett resultsdue
date.
Results of operations related to this transaction
are reported withinreflected in our Lower 48Asia Pacific segment.

Assets Sold

On May 17,

In 2017, we completed the sale of our
50
percent nonoperated interest in the Foster Creek
Christina Lake
(FCCL) Partnership, as well as the majority of
our western Canada gas assets to Cenovus Energy. Energy (CVE).
Consideration for the transaction was $11 billion in cash after customary adjustments, including $600 million related to environmental claims, 208 million Cenovus Energy common shares andincluded a five-year, uncapped contingent payment. The cash proceeds are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. The value of the shares at closing was $1.96 billion based on a price of $9.41 per share on the New York Stock Exchange. The contingent payment,
calculated and paid on a quarterly basis, is $6 million Canadian dollars (CAD)CAD for every $1 CAD by which the Western Canada Select (WCS)WCS quarterly average
crude price exceeds $52 CAD per barrel.

At closing,barrel

. For the carrying valuethree- and six-months ended June
30, 2021, we recorded
contingent payments of our equity investment in FCCL was $8.9 billion. The carrying value of our interest in the western Canada gas assets was $1.9 billion consisting primarily of $2.6 billion of PP&E, partly offset by asset retirement obligations of $585 $
68
million and approximately $100 $
94
million, of environmental and other accruals. Abefore-taxrespectively.
NaN
contingent payments were recorded in
2020.
Contingent payments are recorded as gain of $1.85 billion was included in the “Gain on disposition” line dispositions
on our consolidated income statement for the second quarter of 2017. An additionalbefore-tax gain of $281 million was recognizedand
reflected in our Canada segment.
Planned Dispositions
In July 2021, we entered into divestiture agreements
to sell our interests in certain noncore assets
in our Lower
48 segment.
Proceeds from these agreements total approximately
$
0.2
billion before customary adjustments.
The transactions are expected to close in the third
quarter of 2017. We reportedbefore-tax losses of $26 million and $444 million for the western Canada gas producing properties for the nine-month periods ending September 30, 2017 and

September 30, 2016, respectively. We reportedbefore-tax equity earnings of $197 million and abefore-tax equity loss of $37 million for FCCL for the same periods, respectively. Both FCCL and the western Canada gas assets were reported within our Canada segment.

For more information on the Canada disposition and our investment in Cenovus Energy see 2021.

Note 6—Investment in Cenovus Energy, Note 14—Fair Value Measurement, and Note 15—Accumulated Other Comprehensive Income (Loss).

On July 31, 2017, we completed the sale of our interests in the San Juan Basin to an affiliate of Hilcorp Energy Company for $2.5 billion in cash after customary adjustments, and recognized a loss on disposition of $22 million. The $2.5 billion of cash proceeds are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. The transaction includes a contingent payment of up to $300 million. Thesix-year contingent payment is effective beginning January 1, 2018, and is due annually for the periods in which the monthly U.S. Henry Hub price is at or above $3.20 per million British thermal units.

In the second quarter of 2017, we recorded abefore-tax impairment of $3.3 billion to reduce the carrying value of our interests in the San Juan Basin to fair value. At the time of disposition, the San Juan Basin interests had a net carrying value of approximately $2.5 billion, consisting of $2.9 billion of PP&E and $406 million of liabilities, primarily asset retirement obligations. Thebefore-tax loss associated with our interests in the San Juan Basin, including both the $3.3 billion impairment and $22 million loss on disposition noted above, was $3.2 billion and $226 million for the nine-month periods ended September 30, 2017 and September 30, 2016, respectively. The San Juan Basin results of operations are reported within our Lower 48 segment.

On September 29, 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash after customary adjustments, and recognized abefore-tax loss on disposition of $28 million. The proceeds are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. At the time of the disposition, the carrying value of our interest was $206 million, consisting primarily of $279 million of PP&E and $72 million of asset retirement obligations. Including the $28 million loss on disposition noted above, we reportedbefore-tax losses for the Panhandle properties of $16 million and $28 million for the nine months ended September 30, 2017 and September 30, 2016, respectively. The Panhandle results are reported within our Lower 48 segment.

Note 5—4—Investments, Loans and Long-Term Receivables

Australia Pacific LNG Pty Ltd (APLNG)
APLNG

APLNG’s $8.5  executed project financing agreements

for an $
8.5
billion project finance facility consistsin 2012.
All
amounts were drawn from the facility.
The project financing facility has been restructured
over time and at
June 30, 2021, this facility was composed of a financing agreements executed by APLNG
agreement with the Export-Import Bank of
the United
States, a commercial bank facility and two
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 have been drawn from the facility. Private Placement note facilities.
APLNG made its
first principal and interest repayment in March
2017 and will continueis scheduled to makebi-annual payments
until March 2029.
September 2030.
At SeptemberJune 30, 2017,2021, a balance of $7.9 $
6.0
billion was outstanding on the facility. In connection with the execution of the project financing, we provided a completion guarantee for ourpro-rata share of the project finance facility until the project achieved financial completion. In October 2016, we reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. In August 2017, we reached financial completion for Train 2, which removed the remaining guarantee. current
facilities.
During the first and second quartersfourth quarter of 2017,2020, the outlook for crude oil prices deteriorated, and as a result of significantly reduced price outlooks, the estimated
fair value of our investment in APLNG declined
to an amount
below carrying value. value, primarily due to the weakening
of the U.S. dollar relative to the Australian
dollar.
Based
on a review of the facts and circumstances surrounding
this decline in

fair value, we concluded in the second quarter of 2017 the impairment

was not other than temporary under the guidance
of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC)FASB ASC Topic
323, “Investments – Equity Method and
Joint Ventures,Ventures.”
Due primarily to improved outlooks for
commodity prices and the recognitionstrengthening of an impairmentthe
U.S.
dollar relative to the Australian dollar during the first
six months of 2021, the estimated fair
value of our
investment increased and is above carrying value
at June 30, 2021.
We will continue to fairmonitor the
relationship between the carrying value was necessary. Accordingly, we recorded a noncash $2,384 million, before- andafter-tax impairment in our second-quarter 2017 results. Fair fair
value was estimated based on an internal discounted cash flow model using estimated future production, an outlook of future prices from a combination of exchanges (short-term) and pricing service companies (long-term), costs, a market outlook of foreign exchange rates provided by a third party, and a discount rate believed to be consistent with those used by principal market participants. The impairment was included in the “Impairments” line on our consolidated income statement.

APLNG.

At SeptemberJune 30, 2017,2021, the carrying value of our equity
method investment in APLNG was $7,661 million.
$
6.4
billion.
The
balance is included in the “Investments and long-term
receivables” line item on our consolidated balance
sheet.

FCCL

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. For additional information on the Canada disposition and our investment in Cenovus Energy, see Note 4—Assets Held for Sale or Sold and Note 6—Investment in Cenovus Energy.

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 andnon-affiliated companies.
At SeptemberJune 30, 2017,2021, significant loans to affiliated
companies included $581 $
168
million in project financing to Qatar Liquefied
Gas Company Limited (3) (QG3).

The

10
On our consolidated balance sheet, the long-term
portion of these loans is included in the “Loans
and
advances—related parties” line, on our consolidated balance sheet, while the short-term
portion is in the “Accounts and notes receivable—related parties.”

parties” line.
Note 6-–5—Investment in Cenovus Energy

On May 17, 2017, we completed the sale

Our investment in CVE shares is carried on our
consolidated balance sheet at fair value 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. See Note 4—Assets Held for Sale or Sold, for additional information
$
1.8
billion based
on the Canada disposition.

At closing 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 $

9.58
per share on the New York Stock Exchange. Our ownership approximates to 16.9 NYSE on the last trading day of
the quarter.
At June 30, 2021
and December 31, 2020, we held
188
million and
208
million shares of CVE common
stock, respectively.
At
June 30, 2021, our investment approximated
9.3
percent of the issued and outstanding CenovusCVE common
stock.
During the second quarter, we sold
20
million shares and under an investor agreement with Cenovus Energy, we have agreed not to transfer any of our Cenovus EnergyCVE common shares until six months fromstock, recognizing
proceeds of $
180
million, of which $
166
was received in the closing date (the“Lock-up Termination Date”).

We have classified our investment as anavailable-for-sale equity security on our consolidated balance sheet and, as of September 30, 2017, our investment is carried at fair value of $2.08 billion, reflecting the closing price of Cenovus Energy shares on the New York Stock Exchange of $10.02 per share. The carrying value reflects abefore-tax unrealized gain of $127 million and anafter-tax unrealized gain of $82 million over our cost basis of $1.96 billion. The unrealized gain is reported as a component of accumulated other comprehensive loss. See Note 14—Fair Value Measurement, for additional information. Following theLock-up Termination Date,second quarter.

Subject to market conditions, we intend to
continue to decrease our investment over time through market transactions, private agreements or otherwise.

Note 7—Suspended Wellstime.

All gains and Other Exploration Expenses

The capitalized cost of suspended wells at September 30, 2017, was $872 million, a decrease of $191 million from $1,063 million atyear-end 2016. Two suspended wells in Shenandoah in the Gulf of Mexico totaling $94 million, one suspended well in Alaska totaling $17 million, and one suspended well in Malaysia totaling $23 million were charged to dry hole expense during the first nine months of 2017 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2016.

We reached a settlement agreement on our contract for the Athena drilling rig, initially secured for our four-well commitment program in Angola. As a result of the cancellation, we recorded abefore-tax charge of $43 million net in the first quarter of 2017. This charge is included in the “Exploration expenses” linelosses are recognized within “Other income

(loss)” on our consolidated income statement.

Proceeds related to the sale of our CVE shares
are presented within “Cash Flows from
Investing Activities” on
our consolidated cash flow statement.
Gains and losses recorded in other income (loss)
for our investment in CVE were:
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Total net gain (loss) on equity securities
$
418
551
726
(1,140)
Less: Net gain on equity securities sold during
the period
(31)
0
(60)
0
Unrealized gain (loss) on equity securities still
held at
the reporting date
$
387
551
666
(1,140)
Note 4—Assets Held for Sale or Sold, for additional information on our dispositions. Additionally,6—Debt
Our debt balance at June 30, 2021, was $
20.0
billion compared with $
15.4
billion at December 31, 2020.
On January 15, 2021, we completed the nine-month period acquisition
of 2017 includedConcho in an all-stock transaction.
In the impairmentacquisition,
we assumed Concho’s publicly traded debt, with an outstanding principal
balance of our APLNG investment reported within the Asia Pacific and Middle East segment. For more information, see the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables.The nine-month period also includedan impairment in our Alaska segment in the first quarter of 2017 of $174 million for the associated PP&E carrying$
3.9
billion, which was
recorded at fair value of our small interest in a nonoperated producing property.

In October 2017, we expect to record an estimated $60 millionbefore-tax impairment$

4.7
billion on the acquisition date.
Debt assumed consisted of a gas processing plant in Norway, primarilythe following:
●
3.75
% Notes due to restructured ownership and a change in commercial premises. This impairment will be reflected in ouryear-end results within our Europe and North Africa segment.

In the three- and nine-month periods ended September 30, 2016, our Canada and Asia Pacific and Middle East segments included impairments

2027
with principal of $60 $
1,000
million and $42 
●
4.3
% Notes due
2028
with principal of $
1,000
million respectively, primarily related to certain developed properties in central Alberta and offshore Indonesia, which were written down
●
2.4
% Notes due
2031
with principal of $
500
million
●
4.875
% Notes due
2047
with principal of $
800
million
●
4.85
% Notes due
2048
with principal of $
600
million
The adjustment to fair value less costsof the senior notes
of approximately $
0.8
billion on the acquisition date will be
amortized as an adjustment to sell. Our Europe and North Africa segment included impairmentsinterest expense over
the remaining contractual terms of $20 million in the three-month period ended September 30, 2016, primarily as a result of a canceled project and lower natural gas prices, both in the United Kingdom. In the nine-month period of 2016, our Europe and North Africa segment included impairments of $157 million, primarily as a result of lower natural gas prices in the United Kingdom. Our Lower 48 segment included impairments of $61 millionbefore-tax in the nine-month period of 2016, primarily as a result of lower natural gas prices and increased asset retirement obligation estimates.

The charges discussed below are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above.

Exploration expenses in the three- and nine-month periods of 2017 and 2016 were aligned with our decision announced in 2015 to reduce deepwater exploration spending.

senior notes.
11
In the first quarter of 2017,2021, we recordedcompleted abefore-tax impairment debt
exchange offer related to the debt assumed from Concho.
Of
the approximately $
3.9
billion in aggregate principal amount of $51 Concho’s senior notes
offered in the exchange,
98
percent, or approximately $
3.8
billion, were tendered and accepted.
The new debt issued by
ConocoPhillips had the same interest rates
and maturity dates as the Concho senior notes.
The portion not
exchanged, approximately $
67
million, remained outstanding across five series
of senior notes issued by
Concho.
The debt exchange was treated as a debt modification
for the associated carrying value of capitalized undeveloped leasehold costs of Shenandoahaccounting purposes resulting in deepwater Gulf of Mexico following the suspension of appraisal activity by the operator.

In the second quarter of 2016, we recorded a $203 millionbefore-tax impairment for the associated carrying value of our Gibson and Tiber undeveloped leaseholds in deepwater Gulf of Mexico. In the first quarter of 2016, we recorded a $95 millionbefore-tax impairment for the associated carrying value of capitalized undeveloped leasehold costs portion

of the Melmar prospect, andunamortized fair value adjustment of the majorityConcho
senior notes allocated to the new debt
issued by
ConocoPhillips on the settlement date of a $79 million impairment in deepwater Gulf of Mexico, mainly as a result of changesthe exchange.
The new debt issued in the estimated market value following the completion of an initial marketing effort.

exchange is fully

and
unconditionally guaranteed by ConocoPhillips
Company.
We have a revolving credit facility expiringtotaling $
6.0
billion with an expiration date of
May 2023
.
Our revolving
credit facility may be used for direct bank borrowings,
the issuance of letters of credit totaling
up to $
500
million, or as support for our commercial paper
program.
The revolving credit facility is broadly syndicated
among financial institutions and does not contain
any material adverse change provisions or any covenants
requiring maintenance of specified financial
ratios or credit ratings.
The facility agreement contains a cross-
default provision relating to the failure to pay principal
or interest on other debt obligations of $
200
million or
more by ConocoPhillips, or any of its consolidated
subsidiaries.
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 June 2019, was $6.75 billion. the
London interbank market or at a margin above the overnight
federal funds rate or prime rates offered by
certain designated banks in the U.S.
The facility agreement calls for commitment
fees on available, but
unused, amounts.
The facility 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 twoour ability
to issue up to $
6.0
billion of commercial paper.
Commercial
paper programs: the ConocoPhillips $6.25 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $500 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to
maturities of 90 days.

At September 30, 2017 days

and December 31, 2016, we had no direct outstanding borrowings underis included in the revolving credit facility and no lettersshort-term debt on our consolidated
balance sheet. With $
300
million of credit. We had no commercial paper outstanding at September 30, 2017and
no
direct borrowings or December 31, 2016, under both the ConocoPhillips and the ConocoPhillips Qatar Funding Ltd. commercial paper programs. Since we had no commercial paper outstanding and had issued no letters of
credit, we had access to $6.75 $
5.7
billion in available borrowing capacity under our revolving
credit facility at September June
30, 2017.

2021.

At December 31, 2020, we had $
300
million of commercial paper outstanding
and
no
direct
borrowings or letters of credit issued.
In the first quarterJanuary 2021, Fitch affirmed its rating of 2017, we made a prepayment of $805 million on our floating rate term loan facility due in 2019. In the third quarter of 2017, we prepaid the remaining balance of $645 million.

During the nine-month period of 2017, we redeemed a total $4.8 billion oflong-term debt as described below.

“A” with a “stable” outlook and affirmed its

rating of our short-term debt as “F1+.” On January 25, 2021, S&P revised its industry risk assessment of the
E&P industry to “Moderately High” from “Intermediate” based on a view of increasing risks from the energy
transition, price volatility, and weaker profitability. On February 11, 2021, S&P downgraded its rating of our
long-term debt from “A” to “A-” with a “stable” outlook and downgraded its rating of our short-term debt
from “A-1” to “A-2.” In May 2021, Moody’s affirmed its rating of our senior long-term debt of “A3” with a
“stable” outlook. Moody’s rates our short-term debt as “Prime-2.” 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, upon
downgrade of our credit ratings. If our credit ratings are downgraded from their current levels, it could
increase the second quartercost of 2017,corporate debt available to us and restrict our access to the commercial paper markets. If
our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we redeemed $3.0 billion of debt across the following instruments:

6.65% Debentures due 2018 with principal of $297 million.

5.75% Notes due 2019 with principal of $2.25 billion (partial redemption of $1.7 billion).

would still be able to access funds under our revolving credit facility

6.00% Notes due 2020 with principal of $1.0 billion.

.

In the third quarter of 2017, we redeemed $1.8 billion of debt across the following instruments:

5.20% Notes due 2018 with principal of $500 million.

1.50% Notes due 2018 with principal of $750 million.

5.75% Notes due 2019 with principal of $550 million.

We incurred premiums above book value to redeem the debt instruments of $234 million and $50 million in the second and third quarter of 2017, respectively. These costs are reported in the “Other expense” line on our consolidated income statement.

In October 2017, we gave notice to make a partial redemption of $250 million on the $1.25 billion 4.20% Notes due in 2021. The prepayment will occur in the fourth quarter of 2017, and we expect to incur approximately $20 million in premiums above book value, subject to pricing, related to this redemption when paid.

At SeptemberJune 30, 2017,2021, we had $283 $

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. The
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.

12
Note 10—Noncontrolling Interests

Activity attributable7—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 June 30, 2021
Balances at March 31, 2021
$
21
60,278
(47,672)
(5,080)
35,608
43,155
Net income
2,091
2,091
Other comprehensive income
160
160
Dividends paid ($
0.43
per common stockholders’ equity andshare)
(583)
(583)
Repurchase of company common stock
(606)
(606)
Distributed under benefit plans
59
59
Balances at June 30, 2021
$
21
60,337
(48,278)
(4,920)
37,116
44,276
For the six months ended June 30,
2021
Balances at December 31, 2020
$
18
47,133
(47,297)
(5,218)
35,213
29,849
Net income
3,073
3,073
Other comprehensive income
298
298
Dividends paid ($
0.86
per common share)
(1,171)
(1,171)
Acquisition of Concho
3
13,122
13,125
Repurchase of company common stock
(981)
(981)
Distributed under benefit plans
82
82
Other
1
1
Balances at June 30, 2021
$
21
60,337
(48,278)
(4,920)
37,116
44,276
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 June 30, 2020
Balances at March 31, 2020
$
18
47,027
(47,130)
(6,145)
37,545
72
31,387
Net income
260
18
278
Other comprehensive income
320
320
Dividends paid ($
0.42
per common share)
(455)
(455)
Distributions to noncontrolling interests forand
other
(6)
(6)
Dispositions
(84)
(84)
Distributed under benefit plans
52
52
Other
1
1
Balances at June 30, 2020
$
18
47,079
(47,130)
(5,825)
37,351
0
31,493
For the first ninesix months ended June 30,
2020
Balances at December 31, 2019
$
18
46,983
(46,405)
(5,357)
39,742
69
35,050
Net income
(1,479)
46
(1,433)
Other comprehensive loss
(468)
(468)
Dividends paid ($
0.84
per common share)
(913)
(913)
Repurchase of 2017company common stock
(726)
(726)
Distributions to noncontrolling interests and 2016 was as follows:

                                                                                    
   Millions of Dollars 
   2017  2016 
   Common
Stockholders’
Equity		  Non-
Controlling
Interest		  Total
Equity		  Common
Stockholders’
Equity		  Non-
Controlling
Interest		  Total
Equity		 
  

 

 

  

 

 

 

Balance at January 1

  $34,974   252   35,226   39,762   320   40,082 

Net income (loss)

   (2,434)   43   (2,391)   (3,580)   40   (3,540) 

Dividends

   (986)   —   (986)   (940)   —   (940) 

Repurchase of company common stock

   (2,045)   —   (2,045)   —   —   — 

Distributions to noncontrolling interests

   —   (84)   (84)   —   (75)   (75) 

Other changes, net*

   991   1   992   928   1   929 

 

 

Balance at September 30

  $30,500   212   30,712   36,170   286   36,456 

 

 

*Includes components of

other comprehensive income (loss), which are disclosed separately in the Consolidated Statement of Comprehensive Income.

(32)
(32)
Dispositions
(84)
(84)
Distributed under benefit plans
96
96
Other
1
1
1
3
Balances at June 30, 2020
$
18
47,079
(47,130)
(5,825)
37,351
0
31,493
13
Note 11—8—Guarantees

At SeptemberJune 30, 2017,2021, 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 SeptemberJune 30, 2017,2021, 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 2017 June 2021
exchange rates:

We guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. Our maximum potential amount of future payments related to this guarantee became immaterial in the second quarter of 2017.

We issued a construction completion guarantee related to the third-party project financing secured by APLNG. In October 2016, we reached financial completion for Train 1, releasing a portion of our guarantee. In August 2017, thetwo-train project finance lenders’ test was completed, releasing the remaining guarantee.

●

During the third quarter of 2016, we issued a guarantee
to facilitate the withdrawal of ourpro-rata
portion of the funds in a project finance reserve
account.
We estimate the remaining term of this
guarantee is 12 years.
10 years
.
Our maximum exposure under this guarantee is
approximately $200 $
170
million
and may become payable if an enforcement action
is commenced by the project finance lenders
against APLNG.
At SeptemberJune 30, 2017,2021, the carrying value of this
guarantee was approximately $14 $
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 up
1 to 25 years. 21 years
.
Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated
to be $1 billion$
710
million ($1.75 
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 up
16 to 28
24 years or the life of the venture. venture
.
Our maximum potential amount of future payments
related to these
guarantees is approximately $160 $
180
million and would become payable if APLNG
does not perform.

At

June 30, 2021, the carrying value of these guarantees
was $
11
million.
Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $780 
$
740
million, which consist primarily of guarantees
of the residual value of leased office buildings, guarantees
of the
residual value of leased corporate aircraft,aircrafts, and a guarantee
for our portion of a joint venture’s project finance reserve
accounts.
These guarantees have remaining terms of up
two to sixfive years
and would become payable if upon sale, 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
June 30, 2021, the carrying value of these guarantees
was $
11
million.
Indemnifications

Over the years, we have entered into agreements
to sell ownership interests in certain corporations,
legal entities, joint
ventures and assets that gave rise to qualifying
indemnifications.
These agreements include indemnifications
for taxes and environmental liabilities, employee claims and litigation. The terms of these indemnifications vary greatly. The majorityliabilities.
Most of these indemnifications are related to
tax issues and the
majority of these expire in 2021.
Those related to environmental issues the term ishave terms
that are generally indefinite
and the maximum amountamounts of future payments is are
generally unlimited.
The carrying amount recorded for these indemnificationsindemnification
obligations at September June
30, 2017,2021, was approximately $100 $
50
million.
We amortize the indemnification liability over the relevant time period the
14
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. Included in the recorded carrying amount at September 30, 2017, were approximately $40 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see
Note 12—Contingencies and Commitments.

On March 1, 2015, a supplier to one of the refineries included in Phillips 66 as part of the separation of our downstream businesses formally registered Phillips 66 as a party to the supply agreement, thereby triggering a guarantee we provided at the time of separation. Our maximum potential liability for future payments under this guarantee, which would become payable if Phillips 66 does not perform its contractual obligations under the supply agreement, is approximately $1.28 billion. At September 30, 2017, the carrying value of this guarantee is approximately $98 million and the remaining term is seven years. Because Phillips 66 has indemnified us for losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $98 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee; however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.

Note 12—9—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 butand no amount within the range
is a better estimate than any other amount,
then the minimumlow
end of the range is accrued.
We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we
We accrue receivables for probable insurance or other third-party recoveries. recoveries when applicable.
With respect toincome-tax-related 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 factors 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, weregulations
and record accruals
for environmental liabilities based on management’s best estimates.
These estimates using all information that is available at the time. We measure estimates and base liabilitiesare based 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. Environmental Protection Agency (EPA)EPA or other organizations.
We consider unasserted claims in our determination of environmental
liabilities, and we accrue them in the period they
are both probable and reasonably estimable.

Although liability of those potentially responsible
for environmental remediation costs is generally
joint and
several for federal sites and frequently so for other
sites, we are usually only one of many companies
cited at a
particular site.
Due to the joint and several liabilities, we could
be responsible for all cleanup costs related
to
any site at which we have been designated as a
potentially responsible party.
We have been successful to date
in sharing cleanup costs with other financially
sound companies.
Many of the sites at which we are potentially
responsible are still under investigation by the
EPA or the agency concerned.
Prior to actual cleanup, those
potentially responsible normally assess the
site conditions, apportion responsibility and determine
the

appropriate remediation.
In some instances, we may have no liability
or may attain a settlement of liability.
Where it appears that other potentially responsible
parties may be financially unable to bear their
proportional
share, we consider this inability in estimating
our potential liability, and we adjust our accruals accordingly.
As a result of various acquisitions in the past,
we assumed certain environmental obligations.
Some of these
environmental obligations are mitigated by indemnifications
made by others for our benefit, and some of the
indemnifications are subject to dollar limits
and time limits.

15
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 SeptemberJune 30, 2017,2021, our balance sheet included a total
environmental accrual of $182 $
188
million, compared with $247 
$
180
million at December 31, 2016,2020, for remediation
activities in the United StatesU.S. and Canada.
We expect to incur a
substantial amount of these expenditures within
the next
30 years. years
.
In the future, we may be involved in
additional environmental assessments, cleanups
and proceedings.

Legal Proceedings

Litigation and Other Contingencies
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. operations, and other contract disputes.
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 SeptemberJune 30, 2017,2021, we had performance
obligations secured by letters of credit of $286
$
222
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, we announced we had beenConocoPhillips was unable to reach agreement
with respect to our migration to anthe 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, we filed a request forConocoPhillips
initiated international arbitration on November 2,
2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010.
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. A separate arbitration phase is currently proceeding
In March 2019, the Tribunal unanimously ordered the
government of Venezuela to determinepay ConocoPhillips approximately $
8.7
billion in compensation for the damages owed to ConocoPhillips for Venezuela’s actions. Separate arbitrations for contractual compensation against PDVSA are also pending before International Chamber
government’s unlawful expropriation of Commerce (ICC) arbitration tribunals. In addition,

ConocoPhillips brought fraudulent transfer actionsthe company’s investments in the U.S. District Court of Delaware, alleging that PDVSA has taken actions to improperly expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors.

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by2007.

On August 29,
2019, the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and itsco-venturer and sold the seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed supplemental counterclaims asserting environmental damages, which we believe are not material. The ICSID tribunalTribunal issued a decision on liability on December 14, 2012,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.
16
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 favor of Burlington,April 2018, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of theEcuador-U.S. Bilateral Investment Treaty. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and breach of the U.S.-Ecuador bilateral investment treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for limited environmental and infrastructure impacts associated with the operations of Burlington and itsco-venturer. Ecuador filed a request for annulment of this decision with ICSID, triggering a provisional stay of enforcement of the award. On August 31, the ICSID Annulment Committee issued a decision terminating the provisional stay. The annulment proceeding is ongoing.

In December 2016, PDVSA owed

ConocoPhillips Angola filed a notice of arbitration against Sonangol E.P.approximately $
2
billion under the Block 36 Production Sharing Contract relating to disputes arising thereunder. The arbitration is being conducted under the United Nations Commission on International Trade Laws (UNCITRAL) rules using a three-person tribunal. The arbitration is ongoing.

In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V.their

agreements in connection with the saleexpropriation of the
projects and other pre-expropriation fiscal
measures.
In
August 2018, ConocoPhillips Senegal B.V.entered into a settlement with PDVSA to Woodside Energy Holdings (Senegal) Limitedrecover 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 2016. 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 arbitral tribunal isOffice 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 and the ONRR entered into
a settlement agreement on March 23, 2021,
to resolve the dispute.
All orders and associated appeals have been withdrawn
with prejudice.
Beginning in 2017, cities, counties, governments
and other entities in several states in the processU.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 being constituted.

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 we continue to evaluate our exposure in these
lawsuits.
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.
BSEE’s
order to ConocoPhillips is premised on its connection
to Phillips Petroleum Company, a legacy company of
ConocoPhillips, which held a historical
25
percent interest in this lease and operated 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 is challenging this order.
17
On May 10, 2021, ConocoPhillips filed
arbitration under the rules of the Singapore International
Arbitration
Centre (SIAC) against Santos KOTN Pty Ltd. and
Santos Limited for their failure to timely
pay the $
200
million bonus due upon a final investment decision
(FID) of the Barossa development project under
the sale
and purchase agreement.
Santos KOTN Pty Ltd. and Santos Limited
have filed a response and counterclaim,
and the arbitration is underway.
Note 13—10—Derivative and Financial Instruments

Derivative Instruments

We use futures, forwards, swaps and options in various markets to meet our customer
needs, and capture market opportunities.
opportunities and manage foreign exchange currency
risk.
Commodity Derivative Instruments
Our commodity business primarily consists
of natural gas, crude oil, bitumen, LNG and natural gas liquids.

OurNGLs.

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 normal purchase normal saleNPNS exception are
recognized upon settlement.
We generally apply this exception to eligible crude contracts and certain gas
contracts.
We do not useapply 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
2017		   December 31
2016		 
  

 

 

 

Assets

    

Prepaid expenses and other current assets

  $170    268 

Other assets

   32    44 

Liabilities

    

Other accruals

   167    300 

Other liabilities and deferred credits

   23    34 

 

 

Millions of Dollars
June 30
December 31
2021
2020
Assets
Prepaid expenses and other current assets
$
685
229
Other assets
89
26
Liabilities
Other accruals
688
202
Other liabilities and deferred credits
64
18
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
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Sales and other operating revenues
$
(100)
(50)
(379)
(3)
Other income (loss)
(1)
3
16
5
Purchased commodities
132
24
145
(2)
18
On January 15, 2021, we assumed financial derivative
instruments consisting of oil and natural gas
swaps in
connection with the acquisition of Concho.
At the acquisition date, the financial derivative
instruments
acquired were recognized at fair value as a net liability
of $
456
million with settlement dates under the
contracts through December 31, 2022.
During the first quarter of 2021, we recognized
a loss of $
173
million
on Concho derivative contracts with settlement
dates on or before March 31, 2021, and an additional
$
132
million loss related to all remaining Concho derivative
contracts with settlement dates subsequent
to March 31,
2021, for a total loss of $
305
million.
This loss associated with the acquired financial
instruments is recorded
within the “Sales and other operating revenues”
line on our consolidated income statement were:

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		   Nine Months Ended
September 30		 
   2017  2016   2017  2016 
  

 

 

   

 

 

 

Sales and other operating revenues

  $17   11    120   (155) 

Other income

   (1)   1    (1)   (1) 

Purchased commodities

   (19)   7    (88)   136 

 

 

statement.

By the end of March 2021, all oil and natural
gas derivative financial instruments acquired from
Concho were
contractually settled.
In connection with the settlement, we issued
a cash payment of $
692
million in the first
quarter of 2021 and $
69
million in the second quarter of 2021.
Cash settlements related to the Concho
derivative contracts
are presented within “Cash Flows From
Operating Activities” on our consolidated cash
flow statement.
The table below summarizes our material net exposures
resulting from outstanding commodity
derivative
contracts:

                            
   Open Position
Long/(Short)		 
   September 30
2017		  December 31
2016		 
  

 

 

 
   

Commodity

   

Natural gas and power (billions of cubic feet equivalent)

   

Fixed price

   (33)   (31) 

Basis

   42   2 

 

 

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

Open Position
Long/(Short)
June 30
December 31
2021
2020
Commodity
Natural gas and 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. We do not elect hedge accounting on our foreign currency exchange derivatives.

The following table presents the gross fair valuespower (billions 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
2017		   December 31
2016		 
  

 

 

 

Assets

    

Prepaid expenses and other current assets

  $1    1 

Liabilities

    

Other accruals

   —    168 

 

 

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
September 30		   Nine Months Ended
September 30		 
   2017  2016   2017   2016 
  

 

 

   

 

 

 

Foreign currency transaction (gains) losses

  $(1)   35    2    218 

 

 

We had the following net notional position of outstanding foreign currency exchange derivatives:

                                          
   In Millions
Notional Currency		 
   September 30
2017		   December 31
2016		 
  

 

 

Sell U.S. dollar, buy other currencies*

  USD   26    13 

Buy U.S. dollar, sell other currencies**

  USD   —    25 

Buy British pound, sell other currencies***

  GBP   3    1,069 

Sell British pound, buy Norwegian krone

  GBP   —    51 

 

 

    *Primarily Canadian dollar.

  **Primarily British pound.

***Primarily Euro and Canadian dollar.

cubic feet equivalent)

Fixed price
18
(20)
Basis
(6)
(10)
Financial Instruments

We invest excess cash in financial instruments with maturities based on our cash forecasts for
the various accounts and
currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days.
The types of financial instruments in which we
currently invest include:

●
Time deposits: Interest bearing deposits placed with approvedfinancial
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.

These financial instruments appear in

●
U.S. government or government agency obligations:
Securities issued by the “Cash and cash equivalents” line ofU.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.
19
The following investments are carried on our
consolidated balance sheet ifat cost, plus accrued
interest and the
table reflects remaining maturities at the time we made the investments wereJune
30, 2021 and December 31, 2020:
Millions of Dollars
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
Investments and Long-
Term Receivables
June 30
December 31
June 30
December 31
June 30
December 31
2021
2020
2021
2020
2021
2020
Cash
$
899
597
Demand Deposits
1,541
1,133
Time Deposits
1 to 90 days or less; otherwise,
4,104
1,225
1,537
2,859
91 to 180 days
270
448
Within one year
209
13
One year through five years
2
1
U.S. Government Obligations
1 to 90 days
16
23
0
0
$
6,560
2,978
2,016
3,320
2
1
The following investments in debt securities
classified as available for sale are carried at
fair value on our
consolidated balance sheet at June 30, 2021 and
December 31, 2020:
Millions of Dollars
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
Investments and Long-Term
Receivables
June 30
December 31
June 30
December 31
June 30
December 31
2021
2020
2021
2020
2021
2020
Major Security Type
Corporate Bonds
$
0
0
105
130
182
143
Commercial Paper
48
13
116
155
U.S. Government Obligations
0
0
2
4
8
13
U.S. Government Agency
Obligations
10
17
Foreign Government Obligations
10
0
0
2
Asset-backed Securities
2
0
52
41
$
48
13
235
289
252
216
Cash and Cash Equivalents and Short-Term Investments have remaining maturities
within one year.
Investments and Long-Term Receivables have remaining maturities
greater than one year through eight years.
20
The following table summarizes the amortized
cost basis and fair value of investments in
debt securities
classified as available for sale:
Millions of Dollars
Amortized Cost Basis
Fair Value
June 30
December 31
June 30
December 31
2021
2020
2021
2020
Major Security Type
Corporate bonds
$
286
271
287
273
Commercial paper
164
168
164
168
U.S. government obligations
10
17
10
17
U.S. government agency obligations
10
17
10
17
Foreign government obligations
10
2
10
2
Asset-backed securities
54
41
54
41
$
534
516
535
518
At June 30, 2021 and December 31, 2020, total unrealized
losses for debt securities classified as available
for
sale with net losses were negligible.
Additionally, at June 30, 2021 and December 31, 2020, investments
in
these financial instruments aredebt securities in an unrealized loss
position for which an allowance for
credit losses has not been
recorded were negligible.
For the three-
and six-month periods ended June 30, 2021,
proceeds from sales and redemptions of investments
in debt securities classified as available for sale
were $
173
million and $
320
million, respectively.
For the
three-
and six-month periods ended June 30, 2020, proceeds
from sales and redemptions of investments in
debt
securities classified as available for sale were
$
126
million and $
189
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 “Short-term investments” line on our consolidated balance sheet.

                                                        
   Millions of Dollars 
   Carrying Amount 
   Cash and Cash Equivalents   Short-Term Investments 
   September 30
2017		   December 31
2016		   September 30
2017		   December 31
2016		 
  

 

 

 

Cash

  $925    623    —    — 

Time deposits

        

Remaining maturities from 1 to 90 days

   5,462    2,987    1,103    39 

Remaining maturities from 91 to 180 days

   —    —    74    11 

Commercial paper

        

Remaining maturities from 1 to 90 days

   524    —    1,320    — 

Remaining maturities from 91 to 180 days

   —    —    199    — 

 

 
  $6,911    3,610    2,696    50 

 

 

specific

identification method.
Credit Risk

Financial instruments potentially exposed to concentrations
of credit risk consist primarily of cash equivalents,
short-term investments,over-the-counter (OTC) 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, and time deposits with major international
banks and
financial institutions, high-quality corporate
bonds,
foreign government obligations and asset-backed
securities.
Our long-term investments in debt securities
are placed in high-quality corporate bonds, U.S.
government and government agency obligations,
asset-backed securities, and time deposits
with major
international banks and financial institutions.

The credit risk from our OTC derivative contracts,
such as forwards, swaps and swaps,options, derives
from the
counterparty to the transaction.
Individual counterparty exposure is managed
within predetermined credit
limits and includes the use of cash-call margins when appropriate,
thereby reducing the risk of significant
nonperformance.
We also use futures, swaps and option contracts that have a negligible credit
risk because
these trades are cleared primarily with an exchange
clearinghouse and subject to mandatory margin
requirements until settled; however, we are exposed to the credit
risk of those exchange brokers for receivables
arising from daily margin cash calls, as well as for cash
deposited to meet initial margin requirements.

Our trade receivables result primarily
from our petroleumoil and gas operations and reflect a broad
national and
international customer base, which limits our
exposure to concentrations of credit risk.
The majority of these
receivables have payment terms of
30 days
or less, and we continually monitor this exposure
and the
creditworthiness of the counterparties.
We do not generallymay require collateral to limit the exposure to loss; however, we will sometimes useloss 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.

21
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-relatedcredit risk-related contingent
features that were
in a liability position on Septemberat June 30, 20172021 and December
31, 2016,2020, was $39 $
86
million and $42 $
25
million, respectively.
For these instruments,
no
collateral was posted as of Septemberat June 30, 20172021 or December
31, 2016. 2020.
If our credit rating had
been downgraded below investment grade on September at June
30, 2017,2021, we would behave been required to post $39 
$
70
million
of additional collateral, either with cash or letters
of credit.

Note 14—11—Fair Value
Measurement

We carry a portion of our assets and liabilities at fair value that are measured at athe reporting
date using an exit
price (i.e., the price that would be received to sell
an asset or paid to transfer a liability) and disclosed
according to the quality of valuation inputs under
the following hierarchy:

●
Level 1: Quoted prices (unadjusted) in an active
market for identical assets or liabilities.

●

Level 2: Inputs other than quoted prices that
are directly or indirectly observable.

●

Level 3: Unobservable inputs that are significant
to the fair value of assets or liabilities.

The classification of an asset or liability
is based on the lowest level of input significant
to its fair value.
Those
that are initially classified as Level 3 are subsequently
reported as Level 2 when the fair value derived
from
unobservable inputs is inconsequential to the overall
fair value, or if corroborated market data becomes
available.
Assets and liabilities initially reported as Level
2 are subsequently reported as Level 3 if
corroborated market data is no longer available. Transfers occur at the end of the reporting period.
There were no material transfers ininto or
out of Level 13 during 2017 or 2016.

the three- and six-month periods ended June 30, 2021,
nor during the year ended December 31, 2020.
Recurring Fair Value Measurement

Financial assets and liabilities reported at fair
value on a recurring basis primarily include
our investment in
CVE 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 CVE, 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. This
Level 2 also includes our investmentinvestments in common shares of Cenovus Energy, currently subject to a trading restriction, which is 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 quotes for shares on the New York Stock Exchange. pricing provided by brokers or pricing
service companies that are corroborated with
market
data.
22
●
Level 3 derivative assets and liabilities consist
of OTC swaps, options and forward purchase and
sale
contracts where a significant portion of fair
value is calculated from underlying market
data that is not
readily available.
The derived value uses industry standard methodologies
that may consider the historical
relationships among various commodities, modeled
market prices, time value, volatility factors and other
relevant economic measures.
The use of these inputs results in management’s best estimate of fair
value.
Level 3 activity was not material for all periods
presented.

The following table summarizes the fair value
hierarchy for gross financial assets and
liabilities (i.e.,
unadjusted where the right of setoff exists for commodity
derivatives accounted for at fair value on a recurring
basis):

                                                                                                                
   Millions of Dollars 
   September 30, 2017   December 31, 2016 
   Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 
  

 

 

   

 

 

 

Assets

                

Investment in Cenovus Energy

  $—    2,084    —    2,084    —    —    —    — 

Commodity derivatives

   109    69    24    202    194    96    22    312 

 

 

Total assets

  $109    2,153    24    2,286    194    96    22    312 

 

 

Liabilities

                

Commodity derivatives

  $112    61    17    190    207    105    22    334 

 

 

Total liabilities

  $112    61    17    190    207    105    22    334 

 

 

Millions of Dollars
June 30, 2021
December 31, 2020
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investment in CVE shares
$
1,802
0
0
1,802
1,256
0
0
1,256
Investments in debt securities
10
525
0
535
17
501
0
518
Commodity derivatives
402
349
23
774
142
101
12
255
Total assets
$
2,214
874
23
3,111
1,415
602
12
2,029
Liabilities
Commodity derivatives
$
399
287
66
752
120
91
9
220
Total liabilities
$
399
287
66
752
120
91
9
220
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 
   Gross
Amounts
Recognized		   Gross
Amounts
Offset		   Net
Amounts
Presented		   Cash
Collateral		   Gross Amounts
without
Right of Setoff		   Net
Amounts		 
  

 

 

 

September 30, 2017

            

Assets

  $202    118    84    4    4    76 

Liabilities

   190    118    72    9    3    60 

 

 

December 31, 2016

            

Assets

  $312    221    91    —    5    86 

Liabilities

   334    221    113    12    12    89 

 

 

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
June 30, 2021
Assets
$
774
28
746
464
282
0
282
Liabilities
752
26
726
464
262
17
245
December 31, 2020
Assets
$
255
2
253
157
96
10
86
Liabilities
220
1
219
157
62
4
58
At SeptemberJune 30, 20172021 and December 31, 2016,2020, 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 anon-recurring basis:

                                                        
   Millions of Dollars 
       Fair Value
Measurements Using		 
   Fair Value   Level 1
Inputs		   Level 3
Inputs		   

Before-

Tax Loss

 
  

 

 

   

 

 

   

 

 

   

 

 

 

June 30, 2017(remeasurement date)

        

Net PP&E (held for sale)

  $2,830    2,830    —    3,882 

Cost and equity method investments

   7,656    —    7,656    2,384 

 

 

During the second quarter of 2017, net PP&E held for sale was written down to fair value, less costs to sell. The fair value of each asset was determined by its negotiated selling price. For additional information see Note 4—Assets Held for Sale or Sold.

During the second quarter of 2017, our equity method investment in APLNG was determined to have fair value below its carrying value, and the impairment was considered to be other than temporary. See the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment.

23
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,

Accounts and notes receivable (including long-term and related parties): Thethe carrying amount reported on the balance sheet

is fair value.
●
Accounts and notes receivable (including long-term
and related parties): The carrying amount
reported on the balance sheet approximates fair
value.
The valuation technique and methods used to
estimate the fair value of the current portion
of fixed-rate related party loans is consistent
with Loans
and advances—related parties.

●

Investment in Cenovus Energy shares: CVE:

●
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.
●
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.

●
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.
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 
   2017   2016   2017   2016 
  

 

 

   

 

 

 

Financial assets

        

Investment in Cenovus Energy

  $2,084    —    2,084    — 

Commodity derivatives

   80    91    80    91 

Total loans and advances—related parties

   583    701    583    701 

Financial liabilities

        

Total debt, excluding capital leases

   20,181    26,423    23,451    29,307 

Commodity derivatives

   63    101    63    101 

 

 

Millions of Dollars
Carrying Amount
Fair Value
June 30
December 31
June 30
December 31
2021
2020
2021
2020
Financial assets
Investment in CVE shares
$
1,802
1,256
1,802
1,256
Commodity derivatives
310
88
310
88
Investments in debt securities
535
518
535
518
Loans and advances—related parties
168
220
168
220
Financial liabilities
Total debt, excluding finance leases
19,135
14,478
23,376
19,106
Commodity derivatives
271
59
271
59
24
Note 15—12—Accumulated Other Comprehensive Income (Loss)

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
Income (Loss)		 
  

 

 

 

December 31, 2016

  $(547)   —    (5,646)   (6,193) 

Other comprehensive income

   99   82    720   901 

 

 

September 30, 2017

  $(448)   82    (4,926)   (5,292) 

 

 

There were no items within accumulated other

Millions of Dollars
Defined
Benefit Plans
Net Unrealized
Gain (Loss) on
Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
December 31, 2020
$
(425)
2
(4,795)
(5,218)
Other comprehensive loss related to noncontrolling interests.

income (loss)

134
(1)
165
298
June 30, 2021
$
(291)
1
(4,630)
(4,920)
The following table summarizes reclassifications
out of accumulated other comprehensive loss:

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		   Nine Months Ended
September 30		 
   2017   2016   2017   2016 
  

 

 

   

 

 

 

Defined benefit plans

  $26    27    116    132 

 

 
Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:  $14    13    61    72 

loss and into

net
income (loss):
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Defined benefit plans
$
42
8
54
16
The above amounts are included in the computation of net periodic benefit
cost and are presented net of tax expense of $
11
million and $
2
million for the three-month periods ended June 30, 2021 and June 30, 2020,
respectively, and $
15
million and $
4
million for the six-month
periods ended June 30, 2021 and June 30, 2020, respectively
.
Note 13—Cash Flow Information
Millions of Dollars
Six Months Ended
June 30
2021
2020
Cash Payments
Interest
$
464
397
Income taxes
107
761
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(5,439)
(7,021)
Short-term investments sold
6,842
6,147
Long-term investments purchased
(149)
(208)
Long-term investments sold
48
52
$
1,302
(1,030)
25
Note 14—Employee Benefit Plans
Pension and Postretirement Plans
Millions of Dollars
Pension Benefits
Other Benefits
2021
2020
2021
2020
U.S.
Int'l.
U.S.
Int'l.
Components of Net Periodic Benefit Cost
Three Months Ended June 30
Service cost
$
18
16
21
13
1
0
Interest cost
15
20
17
20
1
1
Expected return on plan assets
(20)
(30)
(21)
(34)
0
0
Amortization of prior service credit
0
0
0
0
(10)
(8)
Recognized net actuarial loss
12
8
13
5
1
0
Settlements
42
0
0
0
0
0
Net periodic benefit cost
$
67
14
30
4
(7)
(7)
Six Months Ended June 30
Service cost
$
39
31
42
27
1
1
Interest cost
28
40
34
42
2
3
Expected return on plan assets
(44)
(60)
(42)
(71)
0
0
Amortization of prior service credit
0
0
0
0
(19)
(16)
Recognized net actuarial loss
27
16
25
11
1
0
Settlements
44
0
1
(1)
0
0
Curtailments
12
0
0
0
0
0
Special Termination Benefits
9
0
0
0
0
0
Net periodic benefit cost
$
115
27
60
8
(15)
(12)
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 three-month period ended June 30,
2021, lump-sum benefit payments exceeded the sum
of
service and interest costs for additional information.

Note 16—Cash Flow Information

                            
   Millions of Dollars 
   Nine Months Ended 
   September 30 
   2017   2016 
  

 

 

  

 

 

 

Cash Payments (Receipts)

   

Interest

  $918   854 

Income taxes*

   574   (339) 

 

 

Net Sales (Purchases) of Short-Term Investments

   

Short-term investments purchased

  $(4,999)   (1,704) 

Short-term investments sold

   2,416   1,475 

 

 
  $(2,583)   (229) 

 

 

*Net the year for the

U.S. qualified pension plan and a U.S. non-qualified
supplemental
retirement plan.
As a result, we recognized a proportionate share
of $569 prior actuarial losses from other
comprehensive income as pension settlement
expense of $
42
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
obligations of the U.S. qualified pension plan
and the U.S. non-qualified supplemental
retirement plan
were remeasured at June 30, 2021.
At the measurement date, the net pension liability
decreased by $
30
million, primarily a result of better actual return
on assets compared with the expected return,
partially offset
by a decrease in 2016 relatedthe discount rate, resulting
in a corresponding increase to refunds received fromother comprehensive
income.
As part of our restructuring program, we concluded
that actions taken during the Internal Revenue Service.

Duringfirst quarter

of 2021, would
result in a significant reduction of future service
of active employees in the U.S. qualified
pension plan, a U.S.
nonqualified supplemental retirement plan and the
U.S. other postretirement benefit plans.
As a result, we
recognized an increase in the benefit obligation
as a curtailment loss of $
12
million on the U.S. pension benefit
plans in the first quarter of 2017, we recognized2021.
In conjunction with the recognition of curtailment
losses, the fair market
values of pension plan assets were updated, and the
pension benefit obligations of the U.S. qualified
pension, a $180 
U.S. nonqualified supplemental retirement
plan and the U.S. other postretirement benefit
plans were
remeasured.
At March 31, 2021, the net pension liability decreased
by $
76
million, adverse cash impact fromprimarily as a result of
discount rate increases for each plan offset by lower than
premised return on assets on the settlement of cross-currency swap transactions which is includedU.S. qualified
pension plan, resulting in a corresponding increase
to other comprehensive income.
26
The relevant discount rates are summarized in
the “Cash Flows From Operating Activities” section of our consolidated statement of cash flow.

Note 17—Employee Benefit Plans

Pension and Postretirement Plans

                                                                                    
   Millions of Dollars 
   Pension Benefits  Other Benefits 
   2017  2016  2017  2016 
  

 

 

  

 

 

  

 

 

 
   U.S.  Int’l.  U.S.  Int’l.       
  

 

 

  

 

 

  

 

 

  

 

 

   

Components of Net Periodic Benefit Cost

       

Three Months Ended September 30

       

Service cost

  $21   20   27   19   —   — 

Interest cost

   29   27   32   30   3   3 

Expected return on plan assets

   (32)   (41)   (34)   (39)   —   — 

Amortization of prior service cost (credit)

   1   (1)   2   (1)   (9)   (9) 

Recognized net actuarial loss (gain)

   17   12   22   6   (1)   — 

Settlements

   21   —   22   —   —   — 

Curtailment Loss

   —   —   14   —   —   1 

 

 

Net periodic benefit cost

  $57   17   85   15   (7)   (5) 

 

 

Nine Months Ended September 30

       

Service cost

  $67   59   82   59   1   1 

Interest cost

   90   78   104   93   7   10 

Expected return on plan assets

   (97)   (119)   (112)   (121)   —   — 

Amortization of prior service cost (credit)

   3   (4)   4   (4)   (27)   (26) 

Recognized net actuarial loss (gain)

   53   36   64   20   (2)   (1) 

Settlements

   118   —   149   —   —   — 

Curtailment Loss

   —   —   14   —   —   1 

 

 

Net periodic benefit cost

  $234   50   305   47   (21)   (15) 

 

 

following table:

June 30
March 31
December 31
Discount rate
2021
2021
2020
U.S. qualified pension plan
%
2.65
3.00
2.40
U.S. nonqualified pension plan
2.15
2.40
1.85
U.S. postretirement benefit plans
*
2.80
2.20
* Not remeasured at June 30, 2021.
During the first ninesix months of 2017,2021, we contributed $783 
$
269
million to our domestic benefit plans and $89 $
63
million
to our international benefit plans.
In 2017,2021, we expect to contribute a total of approximately $800 
$
365
million to
our domestic qualified and nonqualified pension
and postretirement benefit plans and $120 $
97
million to our
international qualified and nonqualified pension
and postretirement benefit plans.

We recognized a proportionate share of prior actuarial losses from other comprehensive income as pension settlement expense of $21 million and $118 million during the three- and nine-month periods ended September 30, 2017, respectively. In conjunction with the recognition of pension settlement expense, the fair market values of U.S. pension plan assets were updated, and the pension benefit obligations of the U.S. qualified pension plan and a U.S. nonqualified supplemental retirement plan were remeasured as of September 30, 2017. As part of the remeasurement, the expected rate of return on the U.S. qualified pension plan assets was reduced from 6.8 percent at January 1, 2017, to 5.8 percent at September 30, 2017.

Severance Accrual

As a result of selling our 50 percent nonoperated interest in the FCCL Partnership and the majority of our western Canada gas assets, as well as our interests in the San Juan Basin, a reduction in our overall employee workforce began during the second quarter of 2017. Severance accruals of $7 million and $62 million were recorded during the three- and nine-month periods ended September 30, 2017, respectively.

The following table summarizes our severance
accrual activity for the nine-monthsix-month period
ended SeptemberJune 30, 2017:

              
   Millions of Dollars 

Balance at December 31, 2016

  $80 

Accruals

   62 

Benefit payments

   (84) 

Foreign currency translation adjustments

   2 

 

 

Balance at September 30, 2017

  $60 

 

 

2021:

Millions of Dollars
Balance at December 31, 2020
$
24
Accruals
102
Benefit payments
(91)
Balance at June 30, 2021
$
35
Accruals include severance costs associated with
our restructuring program.
Of the remaining balance at September June
30, 2017, $36 2021, $
20
million is classified as short-term.

Note 15—Related Party Transactions

Our related parties primarily include equity method
investments and certain trusts for the benefit
of employees.

Significant transactions with our equity affiliates
were:

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Operating revenues and other income

  $24   41   83   96 

Purchases

   26   26   74   75 

Operating expenses and selling, general and administrative expenses

   16   20   42   48 

Net interest (income) expense*

   (4)   (3)   (10)   (9) 

 

 

Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Operating revenues and other income
$
24
21
40
38
Purchases
3
0
3
0
Operating expenses and selling, general and administrative
expenses
63
12
89
27
Net interest (income) expense*
0
(2)
(1)
(4)
*We paid interest to, or received interest from,
various affiliates.
27
Note 19—16—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
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Revenue from contracts with customers
$
7,753
1,919
14,914
6,830
Revenue from contracts outside the scope of ASC
Topic 606
Physical contracts meeting the definition of a derivative
1,754
856
4,728
2,152
Financial derivative contracts
49
(26)
(260)
(75)
Consolidated sales and other operating revenues
$
9,556
2,749
19,382
8,907
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
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
$
1,345
698
3,811
1,674
Canada
207
121
510
300
Europe, Middle East and North Africa
202
37
407
178
Physical contracts meeting the definition of a derivative
$
1,754
856
4,728
2,152
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
178
26
302
118
Natural gas
1,504
763
4,231
1,853
Other
72
67
195
181
Physical contracts meeting the definition of a derivative
$
1,754
856
4,728
2,152
28
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 June 30, 2021, the “Accounts and notes receivable”
line on our consolidated balance sheet,
includes trade
receivables of $
3,504
million compared with $
1,827
million at December 31, 2020, 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.
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, 2020
$
97
Contractual payments received
7
Revenue recognized
(62)
At June 30, 2021
$
42
Amounts Recognized in the Consolidated
Balance Sheet at June 30, 2021
Current liabilities
$
42
For the six-month period of 2021, we recognized revenue of $62 million in the “Sales and other operating
revenues” line on our consolidated income statement. NaN revenue was recognized during the three-month
period ended June 30, 2021. We expect to recognize the contract liabilities as of June 30, 2021, as revenue
during 2022.
29
Note 17—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquidsNGLs on
a worldwide
basis.
We manage our operations through six
6
operating segments, which are primarily defined
by geographic
region: Alaska,Alaska; Lower 48, Canada,48; Canada; Europe, and North Africa, Asia Pacific and
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,income and expense;
premiums on early retirement of debt; corporate
overhead and certain
technology activities, including licensing revenues. revenues;
and unrealized holding gains or losses
on equity securities.
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 in the third quarter of 2020, we 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 prior comparative periods.
On January 15, 2021, we completed our acquisition
of Concho, an independent oil and gas exploration
and
production company with operations across New
Mexico and West Texas.
Results of operations for Concho
are included in our Lower 48 segment for the current
period.
Certain transaction and restructuring costs
associated with the Concho acquisition are included
in our Corporate and Other segment.
30
Analysis of Results by Operating Segment

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Sales and Other Operating Revenues

     

Alaska

  $932   925   3,010   2,639 

 

 

Lower 48

   3,102   2,993   9,422   7,533 

Intersegment eliminations

   (2)   (3)   (7)   (15) 

 

 

Lower 48

   3,100   2,990   9,415   7,518 

 

 

Canada

   699   615   2,357   1,431 

Intersegment eliminations

   (155)   (73)   (330)   (138) 

 

 

Canada

   544   542   2,027   1,293 

 

 

Europe and North Africa

   1,110   946   3,564   2,605 

Asia Pacific and Middle East

   959   942   2,877   2,676 

Corporate and Other

   43   70   94   153 

 

 

Consolidated sales and other operating revenues

  $6,688   6,415   20,987   16,884 

 

 

Net Income (Loss) Attributable to ConocoPhillips

     

Alaska

  $103   59   291   204 

Lower 48

   (97)   (491)   (2,995)   (2,082) 

Canada

   280   (314)   2,607   (783) 

Europe and North Africa

   85   163   379   132 

Asia Pacific and Middle East

   396   (87)   (1,540)   (20) 

Other International

   (20)   (47)   (77)   (100) 

Corporate and Other

   (327)   (323)   (1,099)   (931) 

 

 

Consolidated net income (loss) attributable to ConocoPhillips

  $420   (1,040)   (2,434)   (3,580) 

 

 

                            
   Millions of Dollars 
   September 30
2017		   December 31
2016		 
  

 

 

 

Total Assets

    

Alaska

  $12,094    12,314 

Lower 48

   14,376    22,673 

Canada

   6,281    17,548 

Europe and North Africa

   12,066    11,727 

Asia Pacific and Middle East

   17,094    20,451 

Other International

   122    97 

Corporate and Other

   12,828    4,962 

 

 

Consolidated total assets

  $74,861    89,772 

 

 

Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Sales and Other Operating Revenues
Alaska
$
1,418
419
2,551
1,532
Intersegment eliminations
0
19
0
19
Alaska
1,418
438
2,551
1,551
Lower 48
5,889
1,433
12,402
4,536
Intersegment eliminations
(2)
(28)
(4)
(38)
Lower 48
5,887
1,405
12,398
4,498
Canada
802
165
1,669
678
Intersegment eliminations
(352)
0
(657)
(180)
Canada
450
165
1,012
498
Europe, Middle East and North Africa
1,165
288
2,143
888
Asia Pacific
630
450
1,207
1,453
Other International
2
1
3
4
Corporate and Other
4
2
68
15
Consolidated sales and other operating revenues
$
9,556
2,749
19,382
8,907
Sales and Other Operating Revenues by Geographic Location
(1)
United States
$
7,308
1,844
15,015
6,061
Australia
0
168
0
605
Canada
450
165
1,012
498
China
171
67
326
213
Indonesia
207
132
403
336
Libya
290
0
520
44
Malaysia
252
83
478
299
Norway
618
242
1,030
688
United Kingdom
257
46
593
156
Other foreign countries
3
2
5
7
Worldwide consolidated
$
9,556
2,749
19,382
8,907
Sales and Other Operating Revenues by Product
Crude oil
$
5,797
1,216
10,292
4,660
Natural gas
2,812
1,190
7,323
2,845
Natural gas liquids
325
84
562
235
Other
(2)
622
259
1,205
1,167
Consolidated sales and other operating revenues by product
$
9,556
2,749
19,382
8,907
(1) Sales and other operating revenues are attributable to countries based on the location of
the selling operation.
(2) Includes LNG and bitumen.
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Net Income (Loss) Attributable to ConocoPhillips
Alaska
$
371
(141)
530
(60)
Lower 48
1,175
(365)
1,643
(802)
Canada
102
(86)
112
(195)
Europe, Middle East and North Africa
207
25
360
226
Asia Pacific
175
648
492
920
Other International
(5)
(6)
(9)
22
Corporate and Other
66
185
(55)
(1,590)
Consolidated net income (loss) attributable to ConocoPhillips
$
2,091
260
3,073
(1,479)
31
Millions of Dollars
June 30
December 31
2021
2020
Total Assets
Alaska
$
14,636
14,623
Lower 48
32,309
11,932
Canada
6,991
6,863
Europe, Middle East and North Africa
8,616
8,756
Asia Pacific
10,721
11,231
Other International
239
226
Corporate and Other
11,891
8,987
Consolidated total assets
$
85,403
62,618
Note 20—18—Income Taxes

Our effective tax rate was
32
percent in the three-month period ended June 30,
2021 and was negative for the
comparable period of 2020.
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 CVE common shares.
Our effective tax rates for the third quartersix-months ended June 30,
2021 and nine-month2020 were
36
percent and
7
percent,
respectively and both periods were impacted by the
same items noted above.
Additionally, our effective tax
rate for the six-month period ended SeptemberJune 30, 2017, were 33 percent2021
was adversely impacted by $
75
million due to incremental
interest deductions from the exchange of debt
acquired from Concho offsetting U.S. foreign source revenue
that would otherwise have been offset by foreign tax credits.
The six-month period ending June 30, 2020, was
also impacted by the tax effect of the gain on disposition
recognized for Australia-West assets.
During the three and 39 percent,six-month periods of 2021,
our valuation allowance decreased by $
87
million and $
151
million, respectively, compared with 38 percentto a decrease of $
117
million and 36 percent an increase of $
229
for the same periods of 2016.
2020.
The amounts of U.S. and foreign income (loss) from continuing operations before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes were:

                                                                                                                
   Millions of Dollars  Percent ofPre-Tax Income (Loss) 
   Three Months Ended
September 30		  Nine Months Ended
September 30		  Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016  2017  2016  2017  2016 
  

 

 

  

 

 

  

 

 

  

 

 

 

Income (loss) from continuing operations before income taxes

         

United States

  $(197)   (1,001)   (5,259)   (3,965)   (30.2)%   60.5   133.5   71.8 

Foreign

   850   (653)   1,319   (1,557)   130.2   39.5   (33.5)   28.2 

 

 
  $653   (1,654)   (3,940)   (5,522)   100.0%   100.0   100.0   100.0 

 

 

Federal statutory income tax

  $228   (578)   (1,379)   (1,932)   34.9%   34.9   35.0   35.0 

Non-U.S. effective tax rates

   137   147   503   320   21.0   (8.9)   (12.8)   (5.8) 

U.K. rate change

   —   (138)   —   (138)   —   8.3   —   2.5 

Canada disposition

   (8)   —   (1,176)   —   (1.2)   —   29.8   — 

Recovery of outside basis

   (118)   (15)   (957)   (38)   (18.1)   0.9   24.3   0.7 

Adjustment to tax reserves

   (17)   —   764   —   (2.6)   —   (19.4)   — 

APLNG impairment

   —   —   834   —   —   —   (21.2)   — 

State income tax

   14   (15)   (74)   (126)   2.1   0.9   1.9   2.3 

Enhanced oil recovery credit

   (5)   (28)   (49)   (62)   (0.8)   1.7   1.2   1.1 

Other

   (14)   (1)   (15)   (6)   (2.1)   0.2   0.4   0.1 

 

 
  $217   (628)   (1,549)   (1,982)   33.2%   38.0   39.3   35.9 

 

 

Our effective tax rate for the three- and nine-month periods ended September 30, 2017, was favorably impacted by a tax benefit of $114 million relatedchange to our prior decisionU.S. valuation allowance

for all periods relates primarily to exit Nova Scotia deepwater exploration. This benefit is included in the “Recoveryfair
value
measurement of Outside Tax Basis” lineour CVE common shares and
our expectation of the table above.

tax impact related

to incremental capital
gains and losses.
The impairmentCompany has ongoing income tax audits
in a number of jurisdictions. The government
agents in charge of
these audits regularly request additional time
to complete audits, which we generally grant, and conversely
occasionally close audits unpredictably.
Within the next twelve months we may have audit periods close
that
could significantly impact our APLNG investment in the second quartertotal unrecognized
tax benefits. The amount of 2017 did not generate a tax benefit. See the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment.

Our effective tax rate for the nine-month period ended September 30, 2017, was favorably impacted by a tax benefit of $1,176 million associated with our Canada disposition. The benefit was primarily associated with a deferred tax recovery related to the Canadian capital gains exclusion component of the transaction such change

and the recognition of previously unrealizable Canadian capital asset tax basis. The disposition, along with the associated restructuring of our Canadian operations, may generate an additional tax benefit of $822 million related to the recovery of outside basis. However, since we believe it is not likely we will receive a corresponding cash tax savings of this amount, the benefit has been offset by a full reserve. See Note 4—Assets Held for Sale or Sold, for additional information on our Canada disposition.

In the United Kingdom, legislation was enacted on September 15, 2016, to decrease the overall U.K. upstream corporation tax rate from 50 percent to 40 percent effective January 1, 2016. As a result, a $138 million net tax benefit resulting fromre-measurement of deferred tax liabilities at January 1, 2016, and application of the new rate through September 30, 2016, is reflected in the “Income tax benefit” line on our consolidated income statement.

Note 21—New Accounting Standards

In May 2014, the FASB issued Accounting Standards Update (ASU)No. 2014-09, “Revenue from Contracts with Customers” (ASUNo. 2014-09), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts.

In August 2015, the FASB issued ASUNo. 2015-14, “Deferral of the Effective Date,” which defers the effective date of ASUNo. 2014-09. The ASU is now effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for interim and annual periods beginning after December 15, 2016. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach.

ASUNo. 2014-09 was amended in March 2016 by the provisions of ASUNo. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASUNo. 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASUNo. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASUNo. 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue From Contracts With Customers.”

We will adopt the provisions of ASUNo. 2014-09, as amended, with effect from January 1, 2018, and have elected not to early adopt the standard. We intend to adopt the new standard using the modified retrospective approach which we will apply only to contracts within the scope of the standard that are not complete at the date of initial application. Under this approach, we will apply the guidance retrospectively only to the most current period presented in the financial statements. We continue to assess the

impact of adoption of the standard on our current accounting policies and revenue-related disclosures. The impact to our financial statements is expected to be immaterial.

In January 2016, the FASB issued ASUNo. 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASUNo. 2016-01), to meet its objective of providing more decision-useful information about financial instruments. The ASU, among other things, requires entities to record the changes in fair value of equity investments, other than investments accounted for using the equity method, within net income. Undernot estimable

at this ASU, entities will no longer be able to recognize unrealized holding gains and losses onavailable-for-sale securities in other comprehensive income. The ASU also requires additional disclosures relating to fair value measurement categories for financial assets and liabilities and eliminates certain disclosure requirements related to financial instruments measured at amortized cost. ASUNo. 2016-01 is effective for interim and annual periods beginning after December 15, 2017, and the ASU should be adopted using a cumulative-effect adjustment to retained earningstime.
Our deferred tax liability increased by approximately
$
1.1
billion as part of the date of adoption.

Upon adoption of the standard,liabilities assumed through

our
Concho acquisition.
Additionally, our reserve for unrecognized tax benefits increased by $
150
million related
to tax credit carryovers acquired from Concho
that we will make a cumulative-effect adjustmentdo not expect to reclassify the accumulated unrealized holding gains and losses related to our investment in Cenovus Energy from other comprehensive income to retained earnings, and from the date of adoption, we will begin reporting the changes in the fair value of our investment within net income. The impact on our consolidated financial statements and disclosures will depend on the amount of accumulated unrealized holding gains and losses recognized in other comprehensive income at December 31, 2017, and changes in the fair value of our investment in Cenovus Energy subsequent to that date. recognize.
relating to the Concho acquisition, see Note 6—Investment in Cenovus Energy, Note 14—Fair Value Measurement, and Note 15—Accumulated Other Comprehensive Income (Loss).

In February 2016, the FASB issued ASUNo. 2016-02, “Leases” (ASUNo. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASUNo. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASUNo. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. We plan to adopt ASUNo. 2016-02 effective January 1, 2019, and continue to evaluate the ASU to determine the impact of adoption on our consolidated financial statements and disclosures, accounting policies and systems, business processes, and internal controls. While our evaluation of ASUNo. 2016-02 and related implementation activities are ongoing, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures.

In June 2016, the FASB issued ASUNo. 2016-13, “Measurement of Credit Losses on Financial Instruments” (ASUNo. 2016-13), which sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments based on expected losses rather than incurred losses. The ASU is effective for interim and annual periods beginning after December 15, 2019, and early adoption of the standard is permitted. Entities are required to adopt ASUNo. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. We are currently evaluating the impact of the adoption of this ASU.

3.Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).

All other nonguarantor subsidiaries of ConocoPhillips.

The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

In May 2017, ConocoPhillips Company received a $9.8 billion return of capital from a nonguarantor subsidiary to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.

In September 2017, ConocoPhillips received a $5.0 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.

                                                                                    
   Millions of Dollars 
   Three Months Ended September 30, 2017 
Income Statement  ConocoPhillips  ConocoPhillips
Company		  ConocoPhillips
Canada Funding
Company I		  All Other
Subsidiaries		  Consolidating
Adjustments		  Total
Consolidated		 

Revenues and Other Income

       

Sales and other operating revenues

  $—   2,997   —   3,691   —   6,688 

Equity in earnings (losses) of affiliates

   486   348   —   119   (757)   196 

Gain on dispositions

   —   879   —   (633)   —   246 

Other income

   —   12   —   53   —   65 

Intercompany revenues

   10   77   43   774   (904)   — 

 

 

Total Revenues and Other Income

   496   4,313   43   4,004   (1,661)   7,195 

 

 

Costs and Expenses

       

Purchased commodities

   —   2,666   —   1,001   (741)   2,926 

Production and operating expenses

   —   221   —   1,004   (1)   1,224 

Selling, general and administrative expenses

   2   119   —   11   —   132 

Exploration expenses

   —   30   —   45   —   75 

Depreciation, depletion and amortization

   —   203   —   1,405   —   1,608 

Impairments

   —   1   —   5   —   6 

Taxes other than income taxes

   —   29   —   146   —   175 

Accretion on discounted liabilities

   —   8   —   81   —   89 

Interest and debt expense

   86   169   37   121   (162)   251 

Foreign currency transaction (gains) losses

   (27)   1   77   (46)   —   5 

Other expenses

   50   1   —   —   —   51 

 

 

Total Costs and Expenses

   111   3,448   114   3,773   (904)   6,542 

 

 

Income (Loss) before income taxes

   385   865   (71)   231   (757)   653 

Income tax provision (benefit)

   (35)   379   6   (133)   —   217 

 

 

Net income (loss)

   420   486   (77)   364   (757)   436 

Less: net income attributable to noncontrolling interests

   —   —   —   (16)   —   (16) 

 

 

Net Income (Loss) Attributable to ConocoPhillips

  $420   486   (77)   348   (757)   420 

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

  $1,470   1,536   22   864   (2,422)   1,470 

 

 
Income Statement  Three Months Ended September 30, 2016 

Revenues and Other Income

       

Sales and other operating revenues

  $—   2,933   —   3,482   —   6,415 

Equity in losses of affiliates

   (958)   (397)   —   (26)   1,321   (60) 

Gain on dispositions

   —   11   —   40   —   51 

Other income

   1   3   —   106   —   110 

Intercompany revenues

   18   71   60   793   (942)   — 

 

 

Total Revenues and Other Income

   (939)   2,621   60   4,395   379   6,516 

 

 

Costs and Expenses

       

Purchased commodities

   —   2,563   —   1,024   (768)   2,819 

Production and operating expenses

   —   324   —   1,207   (5)   1,526 

Selling, general and administrative expenses

   2   158   —   43   —   203 

Exploration expenses

   —   192   —   265   —   457 

Depreciation, depletion and amortization

   —   351   —   2,074   —   2,425 

Impairments

   —   —   —   123   —   123 

Taxes other than income taxes

   —   26   —   135   —   161 

Accretion on discounted liabilities

   —   11   —   97   —   108 

Interest and debt expense

   135   159   56   154   (169)   335 

Foreign currency transaction (gains) losses

   8   —   (26)   31   —   13 

 

 

Total Costs and Expenses

   145   3,784   30   5,153   (942)   8,170 

 

 

Income (Loss) before income taxes

   (1,084)   (1,163)   30   (758)   1,321   (1,654) 

Income tax benefit

   (44)   (205)   (4)   (375)   —   (628) 

 

 

Net income (loss)

   (1,040)   (958)   34   (383)   1,321   (1,026) 

Less: net income attributable to noncontrolling interests

   —   —   —   (14)   —   (14) 

 

 

Net Income (Loss) Attributable to ConocoPhillips

  $(1,040)   (958)   34   (397)   1,321   (1,040) 

 

 

Comprehensive Loss Attributable to ConocoPhillips

  $(1,113)   (1,031)   (10)   (460)   1,501   (1,113) 

 

 

                                                                                    
   Millions of Dollars 
   Nine Months Ended September 30, 2017 
Income Statement  ConocoPhillips  ConocoPhillips
Company		  ConocoPhillips
Canada Funding
Company I		  All Other
Subsidiaries		  Consolidating
Adjustments		  Total
Consolidated		 

Revenues and Other Income

       

Sales and other operating revenues

  $—   9,066   —   11,921   —   20,987 

Equity in earnings (losses) of affiliates

   (2,092)   (776)   —   432   3,010   574 

Gain on dispositions

   —   908   —   1,236   —   2,144 

Other income

   1   27   —   115   —   143 

Intercompany revenues

   39   222   126   2,360   (2,747)   — 

 

 

Total Revenues and Other Income

   (2,052)   9,447   126   16,064   263   23,848 

 

 

Costs and Expenses

       

Purchased commodities

   —   8,068   —   3,229   (2,257)   9,040 

Production and operating expenses

   —   501   —   3,351   (3)   3,849 

Selling, general and administrative expenses

   8   365   —   55   (5)   423 

Exploration expenses

   —   435   —   289   —   724 

Depreciation, depletion and amortization

   —   658   —   4,554   —   5,212 

Impairments

   —   1,075   —   5,400   —   6,475 

Taxes other than income taxes

   —   114   —   490   —   604 

Accretion on discounted liabilities

   —   28   —   248   —   276 

Interest and debt expense

   340   505   110   399   (482)   872 

Foreign currency transaction (gains) losses

   (49)   3   145   (71)   —   28 

Other expense

   267   18   —   —   —   285 

 

 

Total Costs and Expenses

   566   11,770   255   17,944   (2,747)   27,788 

 

 

Loss before income taxes

   (2,618)   (2,323)   (129)   (1,880)   3,010   (3,940) 

Income tax provision (benefit)

   (184)   (231)   12   (1,146)   —   (1,549) 

 

 

Net loss

   (2,434)   (2,092)   (141)   (734)   3,010   (2,391) 

Less: net income attributable to noncontrolling interests

   —   —   —   (43)   —   (43) 

 

 

Net Loss Attributable to ConocoPhillips

  $(2,434)   (2,092)   (141)   (777)   3,010   (2,434) 

 

 

Comprehensive Income (Loss) Attributable to ConocoPhillips

  $(1,533)   (1,191)   39   (37)   1,189   (1,533) 

 

 
Income Statement  Nine Months Ended September 30, 2016 

Revenues and Other Income

       

Sales and other operating revenues

  $—   7,289   —   9,595   —   16,884 

Equity in earnings of affiliates

   (3,388)   (1,168)   —   (325)   4,752   (129) 

Gain on dispositions

   —   96   —   106   —   202 

Other income (loss)

   1   (2)   —   150   —   149 

Intercompany revenues

   62   220   176   2,246   (2,704)   — 

 

 

Total Revenues and Other Income

   (3,325)   6,435   176   11,772   2,048   17,106 

 

 

Costs and Expenses

       

Purchased commodities

   —   6,409   —   2,585   (1,948)   7,046 

Production and operating expenses

   —   1,065   —   3,502   (242)   4,325 

Selling, general and administrative expenses

   7   448   —   107   (6)   556 

Exploration expenses

   —   1,174   —   398   —   1,572 

Depreciation, depletion and amortization

   —   914   —   6,087   —   7,001 

Impairments

   —   41   —   280   —   321 

Taxes other than income taxes

   —   122   —   416   —   538 

Accretion on discounted liabilities

   —   35   —   294   —   329 

Interest and debt expense

   385   457   168   426   (508)   928 

Foreign currency transaction (gains) losses

   (34)   2   207   (163)   —   12 

 

 

Total Costs and Expenses

   358   10,667   375   13,932   (2,704)   22,628 

 

 

Loss before income taxes

   (3,683)   (4,232)   (199)   (2,160)   4,752   (5,522) 

Income tax provision (benefit)

   (103)   (844)   (3)   (1,032)   —   (1,982) 

 

 

Net loss

   (3,580)   (3,388)   (196)   (1,128)   4,752   (3,540) 

Less: net income attributable to noncontrolling interests

   —   —   —   (40)   —   (40) 

 

 

Net Loss Attributable to ConocoPhillips

  $(3,580)   (3,388)   (196)   (1,168)   4,752   (3,580) 

 

 

Comprehensive Loss Attributable to ConocoPhillips

  $(2,777)   (2,585)   (6)   (230)   2,821   (2,777) 

 

 

                                                                                    
   Millions of Dollars 
   September 30, 2017 
Balance Sheet  ConocoPhillips  ConocoPhillips
Company		   ConocoPhillips
Canada
Funding
Company I		  All Other
Subsidiaries		   Consolidating
Adjustments		  Total
Consolidated		 

Assets

         

Cash and cash equivalents

  $—   226    35   6,650    —   6,911 

Short-term investments

   —   —    —   2,696    —   2,696 

Accounts and notes receivable

   19   1,738    35   3,952    (2,380)   3,364 

Investment in Cenovus Energy

   —   2,084    —   —    —   2,084 

Inventories

   —   138    —   885    —   1,023 

Prepaid expenses and other current assets

   1   128    6   771    (30)   876 

 

 

Total Current Assets

   20   4,314    76   14,954    (2,410)   16,954 

Investments, loans and long-term receivables*

   31,001   52,867    2,493   18,571    (94,775)   10,157 

Net properties, plants and equipment

   —   4,391    —   42,759    (481)   46,669 

Other assets

   34   2,140    188   1,288    (2,569)   1,081 

 

 

Total Assets

  $31,055   63,712    2,757   77,572    (100,235)   74,861 

 

 

Liabilities and Stockholders’ Equity

         

Accounts payable

  $—   2,480    2   3,314    (2,380)   3,416 

Short-term debt

   (5)   1,263    7   78    (12)   1,331 

Accrued income and other taxes

   —   107    —   898    —   1,005 

Employee benefit obligations

   —   379    —   149    —   528 

Other accruals

   57   255    55   514    (30)   851 

 

 

Total Current Liabilities

   52   4,484    64   4,953    (2,422)   7,131 

Long-term debt

   3,785   11,816    1,705   2,845    (478)   19,673 

Asset retirement obligations and accrued environmental costs

   —   490    —   7,273    —   7,763 

Deferred income taxes

   —   —    —   8,267    (2,005)   6,262 

Employee benefit obligations

   —   1,278    —   625    —   1,903 

Other liabilities and deferred credits*

   3,280   8,769    893   14,962    (26,487)   1,417 

 

 

Total Liabilities

   7,117   26,837    2,662   38,925    (31,392)   44,149 

Retained earnings

   21,607   11,914    (682)   9,193    (13,902)   28,130 

Other common stockholders’ equity

   2,331   24,961    777   29,242    (54,941)   2,370 

Noncontrolling interests

   —   —    —   212    —   212 

 

 

Total Liabilities and Stockholders’ Equity

  $31,055   63,712    2,757   77,572    (100,235)   74,861 

 

 

*Includes intercompany loans.

         
Balance Sheet  December 31, 2016 

Assets

         

Cash and cash equivalents

  $—   358    13   3,239    —   3,610 

Short-term investments

   —   —    —   50    —   50 

Accounts and notes receivable

   22   1,968    23   6,103    (4,702)   3,414 

Inventories

   —   84    —   934    —   1,018 

Prepaid expenses and other current assets

   2   116    8   415    (24)   517 

 

 

Total Current Assets

   24   2,526    44   10,741    (4,726)   8,609 

Investments, loans and long-term receivables*

   37,901   64,434    2,296   31,643    (114,602)   21,672 

Net properties, plants and equipment

   —   6,301    —   52,030    —   58,331 

Other assets

   40   2,194    220   1,240    (2,534)   1,160 

 

 

Total Assets

  $37,965   75,455    2,560   95,654    (121,862)   89,772 

 

 

Liabilities and Stockholders’ Equity

         

Accounts payable

  $—   4,683    1   3,671    (4,702)   3,653 

Short-term debt

   (10)   999    6   94    —   1,089 

Accrued income and other taxes

   —   85    —   399    —   484 

Employee benefit obligations

   —   489    —   200    —   689 

Other accruals

   171   271    40   536    (24)   994 

 

 

Total Current Liabilities

   161   6,527    47   4,900    (4,726)   6,909 

Long-term debt

   8,975   12,635    1,710   2,866    —   26,186 

Asset retirement obligations and accrued environmental costs

   —   925    —   7,500    —   8,425 

Deferred income taxes

   —   —    —   10,972    (2,023)   8,949 

Employee benefit obligations

   —   1,901    —   651    —   2,552 

Other liabilities and deferred credits*

   417   10,391    748   17,832    (27,863)   1,525 

 

 

Total Liabilities

   9,553   32,379    2,505   44,721    (34,612)   54,546 

Retained earnings

   25,025   14,015    (541)   12,883    (19,834)   31,548 

Other common stockholders’ equity

   3,387   29,061    596   37,798    (67,416)   3,426 

Noncontrolling interests

   —   —    —   252    —   252 

 

 

Total Liabilities and Stockholders’ Equity

  $37,965   75,455    2,560   95,654    (121,862)   89,772 

 

 

*Includes intercompany loans.

         

                                                                                    
   Millions of Dollars 
   Nine Months Ended September 30, 2017 
Statement of Cash Flows  ConocoPhillips  ConocoPhillips
Company		  ConocoPhillips
Canada
Funding
Company I		  All Other
Subsidiaries		  Consolidating
Adjustments		  Total
Consolidated		 

Cash Flows From Operating Activities

       

Net Cash Provided by (Used in) Operating Activities

  $(161)   634   22   6,868   (2,767)   4,596 

 

 

Cash Flows From Investing Activities

       

Capital expenditures and investments

   —   (1,230)   —   (2,711)   867   (3,074) 

Working capital changes associated with investing activities

   —   36   —   (54)   —   (18) 

Proceeds from asset dispositions

   5,000   10,974   —   12,737   (14,971)   13,740 

Purchases of short-term investments

   —   —   —   (2,583)   —   (2,583) 

Long-term advances/loans—related parties

   —   (74)   —   (20)   94   — 

Collection of advances/loans—related parties

   658   127   —   2,196   (2,866)   115 

Intercompany cash management

   2,903   (2,474)   —   (429)   —   — 

Other

   —   —   —   51   —   51 

 

 

Net Cash Provided by Investing Activities

   8,561   7,359   —   9,187   (16,876)   8,231 

 

 

Cash Flows From Financing Activities

       

Issuance of debt

   —   20   —   74   (94)   — 

Repayment of debt

   (5,459)   (3,146)   —   (855)   2,866   (6,594) 

Issuance of company common stock

   87   —   —   —   (152)   (65) 

Repurchase of company common stock

   (2,045)   —   —   —   —   (2,045) 

Dividends paid

   (986)   —   —   (2,919)   2,919   (986) 

Other

   3   (5,000)   —   (9,187)   14,104   (80) 

 

 

Net Cash Used in Financing Activities

   (8,400)   (8,126)   —   (12,887)   19,643   (9,770) 

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

   —   1   —   243   —   244 

 

 

Net Change in Cash and Cash Equivalents

   —   (132)   22   3,411   —   3,301 

Cash and cash equivalents at beginning of period

   —   358   13   3,239   —   3,610 

 

 

Cash and Cash Equivalents at End of Period

  $—   226   35   6,650   —   6,911 

 

 
Statement of Cash Flows  Nine Months Ended September 30, 2016 

Cash Flows From Operating Activities

       

Net Cash Provided by (Used in) Operating Activities

  $(315)   (124)   (4)   4,307   (904)   2,960 

 

 

Cash Flows From Investing Activities

       

Capital expenditures and investments

   —   (889)   —   (3,382)   401   (3,870) 

Working capital changes associated with investing activities

   —   (135)   —   (266)   —   (401) 

Proceeds from asset dispositions

   2,300   175   —   275   (2,331)   419 

Purchases of short-term investments

   —   —   —   (229)   —   (229) 

Long-term advances/loans—related parties

   —   (803)   —   —   803   — 

Collection of advances/loans—related parties

   —   60   —   1,072   (1,024)   108 

Intercompany cash management

   (2,767)   2,272   —   495   —   — 

Other

   —   3   —   58   —   61 

 

 

Net Cash Provided by (Used in) Investing Activities

   (467)   683   —   (1,977)   (2,151)   (3,912) 

 

 

Cash Flows From Financing Activities

       

Issuance of debt

   1,600   2,994   —   803   (803)   4,594 

Repayment of debt

   —   (964)   —   (899)   1,024   (839) 

Issuance of company common stock

   122   —   —   —   (174)   (52) 

Dividends paid

   (940)   —   —   (1,078)   1,078   (940) 

Other

   —   (2,318)   —   295   1,930   (93) 

 

 

Net Cash Provided by (Used in) Financing Activities

   782   (288)   —   (879)   3,055   2,670 

 

 

Effect of Exchange Rate Changes on Cash and Cash Equivalents

   —   —   —   4   —   4 

 

 

Net Change in Cash and Cash Equivalents

   —   271   (4)   1,455   —   1,722 

Cash and cash equivalents at beginning of period

   —   4   15   2,349   —   2,368 

 

 

Cash and Cash Equivalents at End of Period

  $—   275   11   3,804   —   4,090 

 

 

Item 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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,
“believe,” “budget,” “continue,” “could,” “intend,“effort,”
“estimate,” “expect,” “forecast,” “goal,” “guidance,”
“intend,” “may,” “objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,”
“target,” “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 the world’s largest independent exploration E&P company with operations
and production (E&P) company, based on proved reserves and production of liquids and natural gas. activities in 15 countries.
Our diverse, low cost of supply portfolio primarily includes
resource-rich North American unconventional assets and oil sands assetsplays in Canada; lower-risk North
America;
conventional assets in North America, Europe, Asia
and Australia; several liquefied natural gas (LNG)Asia; LNG developments; oil sands in
Canada; and an
inventory of global conventional and unconventional
exploration prospects.
Headquartered in Houston, Texas,
at June 30, 2021, we had operations and activities in 17 countries,employed approximately 11,600 employees
10,100 people worldwide and had total assets
of $75$85 billion.
Completed Acquisition of Concho Resources Inc.
On January 15, 2021, we completed our acquisition
of Concho Resources Inc. (Concho), an independent
oil
and gas exploration and production company
with operations across New Mexico and West Texas.
The
addition of complementary acreage in the
Delaware and Midland Basins creates a sizeable
Permian presence to
augment our leading unconventional positions
in the Eagle Ford, Bakken and Montney.
Since the closing of the transaction, we have made
significant progress in integrating the two
companies and
have exceeded our own expectations in realizing
synergies and savings that should have long lasting positive
effects on our business.
We previously announced an expected $750 million of annual cost and capital
savings
by 2022.
However, due to additional benefits anticipated from further cost, capital,
and margin improvements,
we now expect approximately $1 billion asin annual
synergies and savings by 2022.
Overview
While commodity prices continued to improve
in the second quarter of September 30, 2017.

Overview

2021, we believe that

prices will
remain cyclical and volatile.
Our view is that a successful business strategy
in the E&P industry must be
resilient in lower price environments, while
also retaining upside during periods of higher prices.
As such, we
are unhedged, remain disciplined in our investment
decisions and are monitoring market
fundamentals,
including OPEC plus updates regarding supply
guidance,
inventory levels, and capital restraint across
the
industry.
Demand is still recovering but has yet to reach
pre-pandemic levels.
The speed and extent of this
recovery will be influenced by whether and at what
pace the COVID-19 restrictions that
have reduced
economic activity and depressed the demand for
our products globally are eased.
33
As the macro energy landscapeenvironment continues to be challenged asevolve,
we have embraced what we believe sector leadership
requires and we call it our triple mandate.
We believe ConocoPhillips can play a valued role in whatever
pathway the energy transition takes by investing in the lowest
cost of supply barrels to help meet global production oversupply has caused ongoing weaknessenergy
demand, delivering competitive returns of and on capital,
and achieving our net-zero ambition on our gross
operated (scope 1 and 2) emissions.
Our triple mandate is supported by financial principles
and allocation priorities that should allow
us to deliver
superior returns through the price cycles.
Our financial principles consist of maintaining
balance sheet
strength, providing peer-leading distributions,
making disciplined investments, and delivering ESG excellence,
all of which are in commodity prices.

service of delivering financial

returns.
Our acquisition of Concho further reinforced
our
value proposition.
In the fourthsecond quarter, total company production was 1,588
MBOED, including 435
MBOED from the Permian Basin, resulting in cash
provided by operating activities of 2016, given our view that commodity prices were likely to remain lower and more volatile, we announced an updated value proposition. Our value proposition principles, which are to maintain a strong investment grade balance sheet, grow our dividend and pursue disciplined growth, remained essentially unchanged; however, we took steps to improve our competitiveness and resilience by establishing clear priorities for allocating future cash flows. $4.3 billion.
In order, these priorities are: invest capital at a level that maintains flat production volumes and pays our existing dividend; grow our existing dividend; reduce debt to a level we believe is sufficient to maintain a strong investment grade rating through price cycles; repurchase shares; and invest capital to grow absolute production. In conjunction with updating our value proposition, we outlined a 2017 to 2019 operating plan that achieves our cash allocation priorities at Brent prices at or above $50 per barrel with asset sales of $5 billion to $8 billion.

Through the first three quarters of 2017, we took significant actions that allowed us to make substantial progress on some of our stated priorities. We have considerably accelerated these priorities with plans to reduce debt to less than $20 billion and triple our annual planned share buybacks from $1 billion to $3 billion, both in 2017. On a longer-term basis,six-

month period ended June 30, 2021, we have adjusted our targeted debt level to $15 billion and aim to repurchase up to $6 billion of our common stock byyear-end 2019. Through the third quarter, we have increased our quarterly dividend by 6 percent to $0.265 per share, made repayments totaling $6.6 billion on our debt, repurchased 45 million shares of our common stock totaling $2 billion and continued the disposition of noncore assets in our portfolio.

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. Total consideration for the transaction was $11

generated $6.3 billion in cash after customary adjustments, 208 million Cenovus Energy shares, provided by operating
activities,
returning $1.2 billion to shareholders through dividends
and a five-year uncapped contingent payment. The contingent payment, calculated$1 billion through share repurchases.
We ended
the quarter with cash, cash equivalents and paid on a quarterly basis, is $6 million Canadian dollars (CAD) for every $1 CAD by short-term
investments totaling $8.9 billion.
In February 2021, we resumed our share repurchase
program at an annualized level of $1.5 billion
which the Western Canada Select (WCS) quarterly average crude price exceeds $52 CAD per barrel. Proceeds from this transaction are being directed to our stated cash priorities.

On July 31, 2017, we completed the sale of our interestswas

increased in the San Juan Basin for total proceeds comprised second quarter to an annualized level
of $2.5 billion for 2021.
Additionally, in cash after customary adjustmentsMay 2021 we announced a paced monetization program related
to the 208 million shares of
Cenovus Energy (CVE) common shares owned at that time.
We plan to fully dispose of our CVE shares by
year-end 2022, however, the sales pace for the remaining shares will be guided
by market conditions, and we
retain discretion to adjust accordingly.
The proceeds from this disposition will be deployed
towards
incremental share repurchases.
During the second quarter of 2021 we sold 20 million
shares or approximately
10 percent of the shares held at December 31, 2020
for $180 million.
Based on current market conditions, in
2021 we anticipate $1 billion in proceeds to be directed
towards our existing share repurchase authorization,
bringing our total 2021 share repurchases to an estimated
$3.5 billion.
These share repurchases along with our annual
dividend of $2.3 billion amount to a contingent paymenttotal of upapproximately
$6
billion in planned distributions for 2021.
In May 2021,
we demonstrated our commitment to $300 million. Thesix-year contingent payment is effective beginning Januarypreserving
our ‘A’
-rated balance sheet by announcing our
intent to reduce the company’s gross debt by $5 billion over five years through
natural and accelerated
maturities.
In June 2021, we affirmed our commitment to ESG leadership
and excellence,
and to the specific targets that
we set in October 2020 when we became the first
U.S.-based oil and gas company to adopt a Paris-aligned
climate-risk strategy.
Our commitment includes:
●
Net-zero ambition for operational (scope 1 2018, and
2) emissions by 2050 with active advocacy
for a price
on carbon to address end-use (scope 3) emissions;
●
Targeting a reduction in operational greenhouse gas emissions intensity by 35 to 45 percent
from 2016
levels by 2030;
●
Zero routine flaring by 2030, with an ambition
to get there by 2025;
●
10 percent reduction target for methane emissions intensity
by 2025, in addition to the 65 percent
reductions we have made since 2015;
●
Adding continuous methane monitoring devices to
our operations with a focus on the larger Lower 48
facilities;
●
Formation of a dedicated low carbon technology
organization responsible for identifying and
prioritizing global emissions reduction initiatives
and is due annually for periodsopportunities associated with the energy
transition including carbon capture, utilization
and storage (CCUS) and hydrogen;
and
●
ESG performance in which the monthly U.S.executive and employee
compensation programs.
cop20212q10qp36i0.gif
34
-
1
2
3
4
20
40
60
80
Q2'19
Q3'19
Q4'19
Q1'20
Q2'20
Q3'20
Q4'20
Q1'21
Q2'21
WTI/Brent
$/Bbl
WTI Crude Oil, Brent Crude Oil and Henry Hub price is at or above $3.20 per million British thermal units (MMBTU). Proceeds from this transaction are being used for general corporate purposes.

On September 29, 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash after customary adjustments. Proceeds from this transaction are being used for general corporate purposes.

On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnett for $305 million subject to net customary adjustments. Proceeds from this transaction will be used for general corporate purposes.

For additional information on our dispositions, see Note 4—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Our asset dispositions are in line with our strategy, announced in November 2016, to focus on lowcost-of-supply projects in our portfolio that strategically fit our development plans. We are focused on delivering on our value proposition, and are aggressively executing on our stated plans, which we believe position the company for success in the current environment of price uncertainty and ongoing volatility.

Natural Gas Prices

Quarterly Averages
WTI - $/Bbl
Brent - $/Bbl
HH - $/MMBTU
HH
$/MMBTU
Operationally, we continue to focusremain focused on safely executing our capital program and remaining attentive to our costs. the business.
Production excluding Libya was 1,202 thousand barrels of oil equivalent per day (MBOED)1,588 MBOED in the third
second quarter of 2017. Our underlying production, which excludes Libya and the third-quarter impact2021, an increase of closed and signed dispositions of 58607 MBOED in 2017 and 429 MBOED in 2016, increased 1.4
or 62 percent, compared with the same period second quarter
of 2016. Underlying production on a per debt-adjusted share basis grew by 19 percent compared2020,
primarily due to the third acquisition of approximately
330 MBOED in the Permian Basin from
our Concho
acquisition and the absence of last year’s economic curtailments
driven by weakness in oil prices
predominantly in operated North American assets.
We re-invested $1.3 billion back into the business in the form of capital expenditures
during the second
quarter, with over half of 2016. Production per debt-adjusted shareour investments focused on flexible,
short-cycle unconventional plays in the Lower
48 segment where our production is calculated on an underlying production basis using ending period debt dividedliquids-weighted
and is accessible to both domestic and export
markets.
For the full year, driven by ending share price plus ending shares outstanding. We believe production per debt-adjusted share is usefulefficiencies we have already captured from the
Concho transaction,
we have
reduced our 2021 capital guidance to investors as it provides a consistent view of production on a total equity basis by converting debt$5.3 billion
and cost guidance to equity and allows$6.1 billion for comparisons across peer companies. We continue to pursue sustainable operating cost reductions within our business. Operating costs include production and operating expense; selling, general and administrative expense; and exploration general and administrative, geological and geophysical, lease rental and other expense.

2021.

Business Environment

Global oil market conditions remain challenged. Global market fundamentals are trending toward a better balance; however, it will take time for the high level of global inventories to drop to more normal levels.

Global oil prices experienced elevated levels of volatility throughout 2016 with first quarter Brent crude oil prices reaching a10-year quarterly average low of $33.89 per barrel. Global oil prices began to improve at the end of 2016 and have continued trending upward in response to stronger global demand and slower production growth.

The energy industry has periodically experienced this type of extreme volatility due to fluctuatingsupply-and-demand conditions.

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, orglobal pandemics, military conflicts,
actions taken by Organization of Petroleum Exporting Countries (OPEC),OPEC plus and other major
oil producing
countries, environmental laws, tax regulations,
governmental policies, and weather-related disruptions. North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to advances in technology responsible for the rapid growth of tight oil production, successful exploration and rising production from the Canadian oil sands.
Our
strategy is to create value through price cycles
by delivering on the financial,
operational and operationalESG priorities
that underpin our value proposition.

Our earnings and operating cash flows generally
correlate with industry price levels for crude oil
and natural gas, the prices of 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 West Texas Intermediate (WTI) WTI
crude oil, Dated Brent crude oil and Henry Hub natural
gas:

LOGO

Brent crude oil prices averaged $52.09$68.83 per barrel
in the second quarter of 2021,
an increase of 136 percent
compared with $29.20 per barrel in the thirdsecond quarter
of 2017, an increase of 14 percent compared with $45.85 per barrel in the third quarter of 2016, and an increase of 5 percent compared with $49.832020.
WTI at Cushing crude oil prices averaged
$66.07 per barrel in the second quarter of 2017. Industry crude prices for WTI averaged $48.16 per barrel in the third quarter of 2017, 2021,
an increase of 7137 percent compared with $44.88 $27.85
per barrel in the third quarter of 2016. WTI prices remained essentially flat with
the second quarter of 2017 reflecting inventory builds from permitting and outages from Hurricane Harvey.

2020.

Oil prices increased alongside the ongoing global
economic recovery following
2020’s COVID closures as well as OPEC plus supply restraint.
35
Henry Hub natural gas prices averaged $2.99 per MMBTU in the third quarter of 2017, an increase of 6 percent compared with $2.81 per MMBTU in the third quarter of 2016, and a decrease of 6 percent compared with $3.19 $2.83
per MMBTU in the second quarter of 2017. Prices improved relative to the same period2021,
an increase of 2016 as a result of lower U.S. inventories and increased exports, but declined from the prior quarter as natural gas production increased65
percent compared with $1.71 per MMBTU in the contiguous United States.

second

quarter of 2020.
Henry Hub prices have increased
due to healthy domestic demand accompanied
by record levels of feedgas demand for LNG exports
to Europe
and Asia.
Our realized bitumen price increased from $17.82averaged $37.60 per barrel
in the thirdsecond quarter of 2016 and $22.422021,
an
increase of
approximately $61 per barrel compared with negative
$23.11 per barrel in the second quarter of 2017, to $24.19 per barrel2020.
The
increase in the thirdsecond quarter of 2017. The change, compared2021 was driven
by higher blend price for Surmont sales,
largely attributed to both periods, was primarily due to improvement in the WCS benchmark
a strengthening of WTI price and changesreduced unutilized
transportation costs which negatively impacted
our
realized bitumen price in costs per barrel resulting from2020.
We continue to optimize bitumen price realizations through the dispositionutilization of our interest
downstream transportation solutions and implementation
of alternate blend capability which results in the FCCL Partnership.

lower

diluent costs.
Our total average realized price was $39.49$50.03 per barrel of oil equivalent (BOE)
BOE in the thirdsecond quarter of 2017, an increase of 33 percent compared 2021,
increased in comparison
with $29.78$23.09 per BOE in the thirdsecond quarter of 2016, reflecting increased average realized prices for all commodities.

2020.
Key Operating and Financial Summary

Significant items during the thirdsecond quarter
of 20172021 and recent announcements included
the following:

Achieved third-quarter

●
Delivered strong operational performance across the
company’s asset base, including successful
planned maintenance turnarounds, resulting in second
quarter production excluding Libya of 1,202 MBOED; 1.4 percent year-over-year underlying production growth 1,547 MBOED,
excluding the impact of closed or signed dispositions; underlying production grew 19 percent on a production per debt-adjusted share basis.

Lowering full-year 2017 expected capital expenditures to $4.5 billion, a 10 percent reduction from initial guidance.

Libya.

Maintaining full-year production guidance despite impacts from Hurricane Harvey, which were offset by increased volumes from our globally diverse portfolio.

●

Cash

Net cash provided by operating activities has exceededwas $4.3
billion, exceeding capital expenditures
and dividendsyear-to-date.

Reduced year-over-year production and operating expenses by 20 percent.

investments of $1.3 billion.

Closed San Juan Basin and Panhandle dispositions. Expect over $16●

Distributed $1.2 billion to shareholders, comprised
of dispositions during 2017.

Repurchased $1.0$0.6 billion in shares, which reduceddividends and $0.6 billion

in
share repurchases.
●
Ended the quarter with cash and cash equivalents
totaling $6.6 billion and short-term investments
of
$2.3 billion, equaling $8.9 billion in ending share count by 2 percent from the endcash,
cash equivalents and short-term investments.
●
Entered into divestiture agreements during July for
certain Lower 48 noncore assets totaling
approximately $0.2 billion, subject to customary
closing adjustments, as part of the second quarter. On track forcompany’s plan to
generate $2 to $3 billion in share repurchases in 2017.

disposition proceeds
over the next 18 months.

Reduced balance sheet debt by $2.4 billion and received credit rating upgrade. On track for less than $20 billion of debt byyear-end.

Released final project financing loan guarantee for APLNG in Australia after successfultwo-train lenders’ test.

Outlook

Outlook

Capital,
Cost and Production Guidance

Fourth-quarter

In June 2021, due to realizing synergistic savings from
our Concho acquisition earlier than anticipated,
we
announced reductions
of full year 2021
operating plan capital and full-year 2017cost guidance by
a combined $300 million.
Capital guidance was reduced to $5.3 billion
and cost guidance to $6.1 billion for the full
year 2021.
Third-quarter 2021 production is expected to be 1,195 1.48
to 1,235 MBOED1.52 MMBOED,
reflecting seasonal turnarounds
planned in Alaska and 1,350 to 1,360 MBOED, respectively. the Asia Pacific region.
This production guidance excludes Libya and reflects expected impacts
assumes that
previously announced divestitures close during
the third quarter of 2021.
All other guidance items are
unchanged.
Depreciation, Depletion and Amortization
DD&A expense was $1.9 billion in the second quarter
of 2021.
Proved reserves estimates were updated in the
current quarter utilizing historical twelve-month
first-of-month average prices, which decreased
second quarter
DD&A expense by approximately $160 million
before-tax.
Depending on price fluctuations, we would expect
reserve estimates to either increase or decrease.
36
RESULTS OF OPERATIONS
Effective with the third quarter of 2020, we have restructured our segments to align with
changes to our
internal organization.
The Middle East business was realigned from the Barnett disposition, which is anticipated Asia Pacific and Middle East
segment
to close in the fourth quarter of 2017.

Full-year guidance for capital expenditures hasEurope and North Africa segment.

The segments have been lowered to $4.5 billion.

renamed the Asia Pacific segment

and the
Europe, Middle East and North Africa segment.
We expect to reduce debt to less than $20 billion byyear-end 2017,have revised segment information disclosures and expect full-year share repurchases of $3 billion.

Marketing Activities

In line with our strategic objectives, we are currently marketing certain noncore assets. On July 31, 2017, we completed the sale of our interests in the San Juan Basin. On September 29, 2017, we completed the sale of our interest in the Panhandle assets. On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnett for $305 million subject to net customary adjustments. Given the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, on May 17, 2017, we adjusted our outlook on total consideration from asset dispositions from the previously stated range of $5 billion to $8 billion over the next two years, to more than $16 billion in 2017.

Impairments

As we continue to market certain noncore assets, it is possible we will incur future impairment charges. While we may incur additional future impairment charges to long-lived assets, it is not reasonably practicable to quantify their financial impacts. These impacts could be material to

segment performance metrics presented within our results of operations for the periods in which they are incurred.

RESULTS OF OPERATIONS

prior comparative periods.
Unless otherwise indicated, discussion of results for the three-
and nine-monthsix-month periods ended SeptemberJune 30, 2017,2021, is
based on a comparison with the corresponding periods of 2016.

2020.

Consolidated Results

A summary of the company’scompany's net income (loss)
attributable to ConocoPhillips by business segment
follows:

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Alaska

  $103   59   291   204 

Lower 48

   (97)   (491)   (2,995)   (2,082) 

Canada

   280   (314)   2,607   (783) 

Europe and North Africa

   85   163   379   132 

Asia Pacific and Middle East

   396   (87)   (1,540)   (20) 

Other International

   (20)   (47)   (77)   (100) 

Corporate and Other

   (327)   (323)   (1,099)   (931) 

 

 

Net income (loss) attributable to ConocoPhillips

  $420   (1,040)   (2,434)   (3,580) 

 

 

Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Alaska
$
371
(141)
530
(60)
Lower 48
1,175
(365)
1,643
(802)
Canada
102
(86)
112
(195)
Europe, Middle East and North Africa
207
25
360
226
Asia Pacific
175
648
492
920
Other International
(5)
(6)
(9)
22
Corporate and Other
66
185
(55)
(1,590)
Net income (loss) attributable to ConocoPhillips
$
2,091
260
3,073
(1,479)
Net income (loss) attributable to ConocoPhillips
in the second quarter of 2021 increased $1,460$1,831 million.
Earnings were positively impacted by:
●
Higher realized commodity prices.
●
Higher sales volumes, primarily due to our
Concho acquisition and absence of production
curtailments
in our operated North American assets.
Second quarter 2021 net income increases were partly
offset by:
●
Higher DD&A expenses primarily due to our
Concho acquisition and the absence of production
curtailments in our operated North American assets,
partially offset by lower rates driven from price-
related reserve revisions due to higher commodity
prices in 2021.
●
Higher production and operating expenses and
taxes other than income taxes, primarily
due to our
Concho acquisition and the absence of production
curtailments in our operated North American
assets.
●
Absence of a $597 million after-tax gain on dispositions
related to our Australia-West divestiture in
May 2020.
Net income (loss) attributable to ConocoPhillips
in the six-month period ended June 30, 2021, increased
$4,552 million.
In addition to the items detailed above, earnings
were positively impacted by:
●
A gain of $726 million after-tax on our CVE
common shares, compared with an after-tax
loss of
$1,140 million in the third quarter and $1,146first half of 2020.
●
Lower impairments by $519 million,
primarily due to the absence of impairments to noncore
gas
assets in our Lower 48 segment.
37
In addition to the items detailed above, the increases
in earnings in the nine-monthsix-month period ended
June 30, 2021,
were partly offset by:
●
Restructuring and transaction expenses of 2017, mainly due to:

approximately

A $1.6 billion

$261 million after-tax gain related to our Concho
acquisition and mark-to-market impacts on certain
key employee compensation programs.
●
Realized losses on hedges of $233 million after-tax
related to derivative positions assumed through
our Concho acquisition.
These derivative positions were settled
entirely within the sale of certain Canadian assets, $190 million of which was recognized in the thirdfirst quarter of 2017
2021.
See the “Segment Results” section for additional
information.
Income Statement Analysis
Unless otherwise indicated, all results in relation to environmental claims.

Income Statement Analysis
are before-tax.

Higher realized commodity prices.

Lower depreciation, depletionSales and amortization (DD&A) expense,other operating revenues for the three-

and six-month periods of 2021 increased $6,807
million and
$10,475 million,
respectively, mainly due to lowerunit-of-production rates from reserve revisionshigher realized commodity prices and disposition impacts.

higher sales
volumes in the

RecognitionLower 48, primarily related to our Concho acquisition

and the absence of deferredproduction curtailments in
our
operated North American assets.
Equity in earnings of affiliates for the three-month period
of 2021 increased $62 million primarily due to
higher earnings driven by higher LNG and crude
prices, partially offset by a higher effective tax benefits totaling $996rate related
to
equity method investments in our Europe, Middle
East, and North Africa segment.
For the six-month period
of 2021, Equity in earnings of affiliates decreased $50 million
primarily due to lower earnings driven by lower
LNG lagging contract prices in 2021 when compared
with the same periods in 2020.
Gain on dispositions for the three-
and six-month periods of 2021 decreased $537
million and $262 million,
respectively, primarily due to the absence of a $587 million gain associated with
our Australia-West
divestiture.
The six-month decrease was partially offset by recognition
of a $200 million FID bonus associated
with our Australia-West divestiture in the first quarter of 2017,2021.
Other income (loss) for the three-month period
of 2021
decreased $137 million and for the six-month
period
increased $1,780 million.
During these periods in 2021, we recognized
gains of $418 million and $726
million,
respectively, on our CVE common shares, compared with a gain of $551 million
and loss of $1,140
million,
respectively, for the same periods in 2020.
Purchased commodities for the three- and six-month
periods of 2021 increased $1,868 million
and $3,690
million, respectively, primarily due to higher gas and crude prices.
In the six-month period of 2021, higher
prices were partly offset by lower crude oil volumes purchased.
Production and operating expenses for the three-
and six-month periods of 2021
increased $332 million and
$542 million, respectively, primarily due to costs associated with additional
volumes in our operated North
American assets related to our Concho acquisition
and the absence of production curtailments.
Selling, general and administrative expenses increased
$275 million in the six-month period of 2021,
primarily
due to higher costs associated with compensation
and benefits, including mark-to-market impacts
of certain
key employee compensation programs,
and transaction and restructuring expenses
associated with our Concho
acquisition.
Exploration expenses for the six-month period of 2021
decreased $144 million, primarily due to the
absence of
an unproved property impairment and dry hole expenses
related to the dispositionKamunsu East Field in Malaysia
and the
absence of certain Canadian assets.

charges associated with the early termination
of our 2020 winter exploration program in Alaska.

Improved equity earnings,

38
DD&A for the three-
and six-month periods of 2021 increased $709
million and $1,184 million, respectively,
mainly due to higher realized prices,production volumes in the
Lower 48 associated with our Concho acquisition
and higher
volumes in each of our North American assets
due to the absence of a third-quarter 2016 deferred tax charge of $174 million resulting from the change of the tax functional currency for APLNG to the U.S. dollar,production curtailments,
Montney ramp
up and lower DD&A from asset disposition impacts. Kelt acquisition in Canada.
These increases were partly offset by lower volumesrates from
price-related reserve
revisions in Lower 48 and Canada.
Impairments decreased $520 million in
the dispositionsix-month period of our interest in the FCCL Partnership.

Lower exploration expenses mainly due to reduced leasehold impairment expense, dry hole costs and other exploration expenses.

Lower production and operating expenses,2021, primarily due to asset disposition impacts.

the
absence of a $511

A $114 million tax benefit in the third quarter of 2017 related to our prior decision to exit Nova Scotia deepwater exploration.

The increases in net income were partly offset by:

Higher proved property and equity investment impairments, including a combined $2.5 billionafter-tax impairment related to the announced sales of our interests in the San Juan Basin and the Barnett, and a $2.4 billion before- andafter-tax impairment of our equity investment in APLNG, all in the second quarter of 2017.

certain non-core gas assets

Lower volumes primarily due to asset dispositions in our Lower 48 segment.

Taxes other than income taxes for the three-
and Canada segmentssix-month periods of 2021 increased
$240 million and normal field decline.

$360

A $225 millionafter-tax charge associated with our early retirement of debt in 2017, $41 million, of which was recognized in the third quarter of 2017.

The absence of a $138 million net deferred tax benefit in the third quarter of 2016, resulting from a change in the U.K. tax rate.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues increased 24 percent in the nine-month period of 2017 mainlyrespectively, primarily due to higher realized prices across all commodities, partly offset by lower sales volumes primarily in our Lower 48 from

our Concho acquisition,
the
absence of production curtailments
in all of our North American assets and Canada segments.

Equityhigher commodity

prices.
Foreign currency transaction (gain) loss in earnings (losses)the
six-month period of affiliates increased $2562021 was a loss of $29 million
compared
with a gain of $83 million in the third quarter and $703six-month period
of 2020.
This increase of $112 million in the nine-month period of 2017. The increase in equity earnings in the third quarter was primarily due to
the absence of a 2016 deferredgains recognized from foreign currency
derivatives and other foreign currency remeasurements.
See
for information regarding our income tax charge of $174 million resulting from aprovision
(benefit) and effective tax functional currency change; higher realized commodity prices at APLNG and Qatar Liquefied Gas Company Limited (3) (QG3); reduced DD&A driven by the disposition of our interest in the FCCL Partnership; and increased volumes at APLNG given theramp-up of Trains 1 and 2. The increase in earnings was partly offset by lower volumes as a result of our FCCL disposition.

In the nine-month period, equity in earnings of

rate.
39
Summary Operating Statistics
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Average Net Production
Crude oil (MBD)
Consolidated operations
836
460
820
551
Equity affiliates was further improved due to higher bitumen prices at FCCL prior to the disposition.

Gain on dispositions increased $195 million in the third quarter and $1,942 million in the nine-month period of 2017. The increase in the three- and nine-month periods of 2017 was primarily due tobefore-tax gains of $1.9 billion and $281 million in the second and third quarters of 2017, respectively, on the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada

13
14
13
13
Total crude oil
849
474
833
564
Natural gas assets.

Purchased commodities increased 28 percent in the nine-month period of 2017, largely due to higherliquids (MBD)

Consolidated operations
120
85
113
101
Equity affiliates
8
8
8
7
Total natural gas prices.

liquids

128
93
121
108
Bitumen (MBD)
68
34
69
50
Natural gas (MMCFD)
Consolidated operations
2,209
1,221
2,142
1,429
Equity affiliates
1,051
1,056
1,066
1,046
Total natural gas
3,260
2,277
3,208
2,475
Total Production
(MBOED)
1,588
981
1,558
1,135
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated operations*
$
65.54
25.10
61.60
38.81
Equity affiliates
64.10
25.32
62.03
38.52
Total crude oil
65.51
25.10
61.60
38.80
Natural gas liquids (per bbl)
Consolidated operations
25.62
8.29
25.06
10.85
Equity affiliates
44.12
23.93
46.53
32.38
Total natural gas liquids
26.87
9.88
26.68
12.63
Bitumen (per bbl)
37.60
(23.11)
34.09
(3.09)
Natural gas (per MCF)
Consolidated operations*
4.25
2.64
4.56
3.19
Equity affiliates
3.97
3.90
3.76
4.65
Total natural gas
4.16
3.22
4.29
3.81
Millions of Dollars
Exploration Expenses
General administrative, geological and operating expenses decreased 20 percent ingeophysical,
lease rental, and other
$
56
94
134
215
Leasehold impairment
1
-
1
31
Dry holes
-
3
6
39
$
57
97
141
285
*Average sales prices, including the third quarter and 11 percent in the nine-month periodimpact of 2017, primarily due to disposition impacts and lower costs and activity across segments.

SG&A expenses decreased 24 percent in the nine-month period of 2017, primarily due to lower restructuring costs and pension settlement expenses.

Exploration expenses decreased 84 percent in the third quarter primarily due to reduced other exploration expenses and dry hole costs. In addition to these factors, exploration expenses decreased 54 percent in the nine-month period of 2017 due to reduced leasehold impairment expense.

Other exploration expenses were reduced mainly due to the absence of a $134 million expense in the third quarter of 2016 related to the cancellation of our final Gulf of Mexico deepwater drillship contract.

Dry hole costs were reduced primarily due to the absence ofbefore-tax charges in deepwater Gulf of Mexico of $249 million mainly in the second quarter of 2016 for our Gibson and Tiber wells, and $128 million in thesix-month period of 2016 for our Melmar well. The absence of a $164 million charge in the third quarter of 2016 for a dry hole in Nova Scotia also reduced costs in the three- and nine-month periods. The reduction in dry hole costs was partly offset bybefore-tax charges totaling $291 millionhedges settling per initial contract

terms in the first quarter of 2017 for multiple wells in Shenandoah, including wells previously suspended.

Leasehold impairment expense was reduced mainly due to the absence of 2016before-tax charges of $203 million in the second quarter for our Gibson and Tiber leaseholds. The expense was further reduced by the absence ofbefore-tax charges, primarily in the first quarter, of $95 million for our Melmar leasehold and $79 million for various Gulf of Mexico leases after completion of an initial marketing effort. The reduction was partly offset by abefore-tax charge of $51 million in the first quarter of 2017 for Shenandoah in deepwater Gulf of Mexico.

For additional information on other exploration expenses, dry hole costs and leasehold impairments, see Note 7—Suspended Wells and Other Exploration Expenses and Note 8—Impairments, in the Notes to Consolidated Financial Statements.

DD&A decreased 34 percent in the third quarter and 26 percent in the nine-month period of 2017, mainly due to lowerunit-of-production rates from reserve revisions and disposition impacts2021 assumed in our CanadaConcho

acquisition, were $60.59 per barrel for crude oil and Lower 48 segments.

Impairments decreased $117 million in$4.50 per mcf for natural gas for the third quartersix-month

period ended June 30, 2021.
As of March
31, 2021, we had settled all oil and increased $6.2 billion in the nine-month period of 2017. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Other expense includedbefore-tax charges of $234 million and $51 million in the second and third quarters of 2017, respectively, for premiums on early debt retirements.

gas hedging positions acquired from Concho.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements,10 for information regarding ourincome tax provision (benefit) and effective tax rate.

Summary Operating Statistics

                                                        
   Three Months Ended
September 30		   Nine Months Ended
September 30		 
   2017  2016   2017   2016 
  

 

 

   

 

 

 

Average Net Production

       

Crude oil (MBD)*

   582   586    591    598 

Natural gas liquids (MBD)

   95   148    119    146 

Bitumen (MBD)

   63   193    140    173 

Natural gas (MMCFD)**

   2,918   3,777    3,405    3,855 

 

 

Total Production(MBOED)***

   1,226   1,557    1,418    1,560 

 

 
   Dollars Per Unit 

Average Sales Prices

       

Crude oil (per barrel)

  $49.39   43.21    49.51    38.97 

Natural gas liquids (per barrel)

   23.82   16.18    23.25    15.04 

Bitumen (per barrel)

   24.19   17.82    22.25    12.65 

Natural gas (per thousand cubic feet)

   4.11   3.05    3.91    2.85 

 

 
   Millions of Dollars 

Exploration Expenses

       

General administrative, geological and geophysical, lease rental, and other

  $68   270    289    562 

Leasehold impairment

   10   24    81    418 

Dry holes

   (3)   163    354    592 

 

 
  $75   457    724    1,572 

 

 

    *Thousands of barrels per day.

  **Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

***Thousands of barrels of oil equivalent per day.

additional information.

40
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquidsNGLs on
a worldwide
basis.
At SeptemberJune 30, 2017,2021, our operations were producing
in the United States,U.S., Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia,
China, Malaysia,
Qatar and Libya.

Total production from operations decreased 21of 1,588 MBOED increased 607 MBOED or 62 percent in
the second quarter of 2021 and
423 MBOED or 37 percent in the thirdsix-month period
of 2021,
primarily due to:
●
Higher volumes in the Lower 48 due to our
Concho acquisition.
●
Higher volumes in our operated North American
assets and Malaysia due to the absence
of production
curtailments.
●
New wells online in the Lower 48, Canada,
Norway, Malaysia, and Australia.
●
Higher production in Libya due the absence of
a forced shutdown of the Es Sider export terminal
and
other eastern export terminals after a period of
civil unrest.
The increase in the second quarter and 9 percent in the nine-month six-month
period of 2017. The decrease in total average production in both periods,2021 was partly offset by:
●
Normal field decline.
●
Disposition activity primarily resulted from noncore asset dispositions, includingrelated to our Canada and San Juan transactions which were
Australia-West divestiture completed in the second and third quarters
quarter of 2017, respectively, and normal field decline. The decrease2020.
In addition to the items detailed above, in the six-month
period of 2021, production was partly offset by production from major developments, including tight oil playsalso decreased
due to:
●
Higher unplanned downtime in the Lower 48; Malikai48
due to Winter Storm Uri, which impacted production by
approximately 50 MBOED in the first quarter
of 2021.
Production excluding Libya for the second quarter
of 2021 was 1,547 MBOED, an increase of 566
MBOED
from the same period a year ago.
After adjusting for closed acquisitions and the Kebabangan gas field in Malaysia; Surmont 2 in Canada; and APLNG in Australia. Improved drilling and well performance in Alaska, Norway and China; dispositions
as well as estimated
impacts from the resumption2020 curtailment program, second-quarter
2021 production increased 46 MBOED or 3
percent.
This increase was primarily due to new production
from the Lower 48 andramp-up of production other development
programs across the portfolio, partially offset by normal
field decline.
Production from Libya also partly offset the decrease in production in both periods. In the third quarter of 2017, we achieved production of 1,226 averaged 41
MBOED. Excluding
Production excluding Libya third-quarter production was 1,202 MBOED. Adjusted for the third-quarter impact six-month period
of 2021 was 1,518 MBOED, an increase
of 388 MBOED
from the same period a year ago.
After adjusting for closed acquisitions and signed dispositions, of 58 MBOED in 2017
estimated impacts
from the 2020 curtailment program and 429 MBOED in 2016, our underlyingWinter Storm Uri impacts
from 2021, production increased 16 MBOED, or 1.4 percent, compared with18
MBOED.
This increase was primarily due to new production
from the third quarter of 2016.

On May 17, 2017, we completedLower 48 and other development

programs across the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as most of our western Canadaportfolio, partially offset by normal
field decline.
Production from Libya averaged 40
MBOED.
41
Segment Results
Alaska
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Net income (loss) attributable to ConocoPhillips
($MM)
$
371
(141)
530
(60)
Average Net Production
Crude oil (MBD)
184
153
187
175
Natural gas assets to Cenovus Energy.liquids (MBD)
15
13
16
16
Natural gas (MMCFD)
11
8
10
8
Total Production associated with these assets was 260 MBOED in the third quarter of 2016, and 138 MBOED and 257 MBOED in the nine-month periods of 2017 and 2016, respectively.

On July 31, 2017, we completed the sale of our interests in the San Juan Basin, which produced 40 MBOED and 123 MBOED in the third quarters of 2017 and 2016, respectively, and 90 MBOED and 124 MBOED in the corresponding nine-month periods.

On September 29, 2017, we completed the sale of our interest in the Panhandle assets, which produced 8 MBOED and 6 MBOED in the third quarters of 2017 and 2016, respectively, and 8 MBOED and 7 MBOED in the corresponding nine-month periods.

On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnett, which produced 10 MBOED and 11 MBOED in the third quarters and nine-month periods of 2017 and 2016, respectively. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the fourth quarter of 2017.

Year-end 2016 reserves associated with our Canadian transaction and the disposition of our interests in the San Juan Basin were 1.3 billion barrels of

(MBOED)
201
167
205
192
Average Sales Prices
Crude oil equivalent (BBOE) and 0.6 BBOE, respectively.

Segment Results

Alaska

                                                        
     Three Months Ended
September 30		     Nine Months Ended
September 30		 
     2017     2016     2017     2016 
    

 

 

     

 

 

 

Net Income Attributable to ConocoPhillips(millions of dollars)

    $103      59      291      204 

 

 

Average Net Production

                

Crude oil (MBD)

     154      148      166      160 

Natural gas liquids (MBD)

     11      11      14      12 

Natural gas (MMCFD)

     5      18      7      28 

 

 

Total Production(MBOED)

     166      162      181      177 

 

 

Average Sales Prices

                

Crude oil (dollars per barrel)

    $50.53      43.43      50.81      39.69 

Natural gas (dollars per thousand cubic feet)

     4.55      6.95      2.77      5.20 

 

 

($ per bbl)

$
67.87
26.81
63.93
42.52
Natural gas ($ per MCF)
4.53
2.56
3.17
2.82
The Alaska segment primarily explores for, produces, transports
and markets crude oil, natural gas liquidsNGLs and natural gas.
As of SeptemberJune 30, 2017,2021, Alaska contributed 2120 percent
of our worldwideconsolidated liquids production and less
than 1
percent of our worldwideconsolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips
Earnings from Alaska increased 75 percent $512 million
in the thirdsecond quarter of 2021
and 43 percentincreased $590 million in the nine-month
six-month period of 2017. The2021, respectively.
Earnings were positively impacted by:
●
Higher realized crude oil prices.
●
Higher volumes due to the absence of production
curtailments.
●
Lower exploration expenses due to the absence
of charges associated with the early cancellation of our
2020 winter exploration program.
Partly offsetting the increase in earnings was:
●
Higher DD&A expenses primarily driven
by higher production volumes and higher rates.
Production
Average production increased 34 MBOED in the thirdsecond quarter of 2021 and 13 MBOED
in the six-month
period of 2021, respectively.
The increase was primarily due to higher crude oil realized prices and lower DD&A expense from reserve revisions. The earnings improvement was partly offset by adverse tax impacts including adjustments toto:
●
Absence of curtailments at our worldwide tax apportionment and enhanced oil recovery tax credits.

In addition tooperated assets.

Partly offsetting the items discussed above, earnings increased in the nine-month period of 2017 due to lower production and operating expenses from reduced activity. The earnings increase in the nine-month period was partly offset by a $110 millionafter-tax impairment charge for the associated properties, plants and equipment carrying value of our small interest in a nonoperated producing property; the absence of a $57 million after-tax benefit in 2016 for the recognition of state deferred tax assets; and higher exploration expense from increased seismic activity in the Western North Slope and higher dry hole costs.

production was:

●
Normal field decline.
42
Lower 48
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
1,175
(365)
1,643
(802)
Average production increased 2 percent in the third quarter and the nine-month period of 2017, asNet Production
Crude oil (MBD)
454
166
435
218
Natural gas liquids (MBD)
97
64
89
77
Natural gas (MMCFD)
1,459
486
1,389
582
Total Production
(MBOED)
794
311
755
392
Average Sales Prices
Crude oil ($ per bbl)*
$
64.13
19.87
60.17
32.92
Natural gas liquids ($ per bbl)
24.62
6.95
24.34
9.81
Natural gas ($ per MCF)*
3.27
1.18
3.88
1.36
*Average sales prices, including the impact of normal field decline was more than offset by well performancehedges settling per initial contract
terms in the Western North Slope, Greater Prudhoefirst quarter of 2021 assumed in our Concho
acquisition, were $58.25 per barrel for crude oil and Greater Kuparuk areas$3.78 per mcf for natural gas for the six-month
period ended June 30, 2021.
As of March
31, 2021, we had settled all oil and lower downtime.

Lower 48

                                                        
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Net Loss Attributable to ConocoPhillips(millions of dollars)

  $(97)   (491)   (2,995)   (2,082) 

 

 

Average Net Production

     

Crude oil (MBD)

   175   195   176   201 

Natural gas liquids (MBD)

   64   92   73   89 

Natural gas (MMCFD)

   765   1,224   1,007   1,228 

 

 

Total Production(MBOED)

   366   491   417   495 

 

 

Average Sales Prices

     

Crude oil (dollars per barrel)

  $45.29   40.09   44.84   35.54 

Natural gas liquids (dollars per barrel)

   20.72   14.57   20.55   12.93 

Natural gas (dollars per thousand cubic feet)

   2.63   2.59   2.74   2.03 

 

 

gas hedging positions acquired from Concho.

.
The Lower 48 segment consists of operations located
in the U.S. Lower 48 states, as well as producing
properties and exploration activities in the Gulf of Mexico.
As of SeptemberJune 30, 2017,2021, the Lower 48 contributed 30
53 percent of our worldwide
consolidated liquids production and 3065 percent
of our worldwideconsolidated natural gas production.

Losses

Net Income (Loss) Attributable to ConocoPhillips
Earnings from the Lower 48 decreased 80 percent increased $1,540 million
in the thirdsecond quarter primarily of 2021 and increased $2,445
million in the six-month period of 2021, respectively.
Earnings were positively impacted by:
●
Higher sales volumes of crude oil and natural gas
due to lower DD&A expense, mainly resulting from a lowerunit-of-production rate from reserve revisions, disposition impactsour Concho acquisition and lower volumes; lower exploration expenses mainly resulting from the absence
of $87 millionafter-tax in rig cancellation and related third-party costs for our final Gulf of Mexico deepwater drillship contract; and higher
production curtailments.
●
Higher realized crude oil, natural gas, liquids and natural gas NGL
prices. The
Partly offsetting the increase in earnings improvement in the third quarter was partly was:
●
Higher DD&A expenses primarily due to higher
production from our Concho acquisition
and absence
of production related curtailment partially
offset by lower volumesrates from normal field decline and asset dispositions.

Losses from Lower 48 increased 44 percent in the nine-month period of 2017. The factors discussed above, along with the absence of 2016after-tax dry hole costs and leasehold impairment charges totaling $439 million related to our Gibson, Tiber and Melmar wells and leases and lowerprice-related reserve revisions.

●
Higher production and operating expenses were moreand
taxes other than offset by 2017 proved property impairments totaling $2.5 billionafter-tax forincome taxes, primarily
due to higher
production from our interestsConcho acquisition and the absence
of production curtailments.
In addition to the items detailed above, in the San Juan Basin and the Barnett.

In the third quartersix-month

period of 2017, our average realized crude oil price2021, earnings also increased due to:
●
The absence of $45.29 per barrel was 6 percent less than WTI of $48.16 per barrel. The differential is driven primarily by local market dynamics$399 million in after-tax impairments
related to certain noncore gas assets in the Gulf Coast and Bakken, and may widenWind
River Basin operations area.
In addition to the items detailed above, in the near term.

Total averagesix-month

period of 2021, earnings also decreased due
to:
●
Realized losses on hedges related to derivative
positions acquired in our Concho acquisition.
●
Higher selling, general and administrative
expenses, primarily due to transaction and restructuring
charges related
to our Concho acquisition.
43
Production
Average production decreased 25 percentincreased 483 MBOED and 363 MBOED in the third quarter three-
and 16 percentsix-month periods of 2021,
respectively, primarily due to:
●
Higher volumes due to our Concho acquisition.
●
New wells online from our development programs
in Eagle Ford, Permian and Bakken.
●
Absence of curtailments.
These production increases were partly offset by:
●
Normal field decline.
In addition to the items detailed above, in the nine-month six-month
period of 2017. The decrease was mainly attributable2021, production also decreased
due to:
●
Higher unplanned downtime, primarily due to normal field decline, the disposition of our interests in the San Juan Basin and Hurricane Harvey impacts to our Eagle Ford operations in the third quarter, partly offset by new production, primarily from Eagle Ford, Bakken and the Permian Basin.

Asset Disposition Update

On

Winter Storm Uri.
Planned Dispositions
In July 31, 2017,2021, we completed the sale of our interests in the San Juan Basin for total proceeds comprised of $2.5 billion in cash after customary adjustments and a contingent payment of up to $300 million. Thesix-year contingent payment is effective beginning January 1, 2018, and is due annually for the periods in which the monthly U.S. Henry Hub price is at or above $3.20 per million British thermal units.

On September 29, 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash after customary adjustments.

On June 28, 2017, we signed a definitive agreement with an affiliate of Miller Thomson & Partners LLC entered into divestiture agreements

to sell our interests in the Barnett for $305 million certain noncore assets
in cash, subject toour Lower
48 segment.
Proceeds from these agreements total approximately
$0.2 billion before customary adjustments.
The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and istransactions are expected to close in the fourth third
quarter of 2017.

See Note 4—Assets Held for Sale or Sold, in the Notes2021.

Canada
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Net Income (Loss) Attributable to Consolidated Financial Statements, for additional information regarding our asset dispositions.

Canada

                                                        
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017   2016  2017   2016 
  

 

 

  

 

 

 

Net Income (Loss) Attributable to ConocoPhillips(millions of dollars)

  $280    (314)   2,607    (783) 

 

 

Average Net Production

       

Crude oil (MBD)

   1    7   3    8 

Natural gas liquids (MBD)

   1    23   12    23 

Bitumen (MBD)

       

Consolidated operations

   63    41   56    29 

Equity affiliates

   —    152   84    144 

 

 

Total bitumen

   63    193   140    173 

Natural gas (MMCFD)

   10    517   246    538 

 

 

Total Production(MBOED)

   67    309   196    294 

 

 

Average Sales Prices

       

Crude oil (dollars per barrel)

  $—    37.50   43.46    33.47 

Natural gas liquids (dollars per barrel)

   —    14.99   21.44    13.41 

Bitumen (dollars per barrel)

       

Consolidated operations

   24.19    15.73   19.93    11.36 

Equity affiliates

   —    18.39   23.83    12.91 

Total bitumen

   24.19    17.82   22.25    12.65 

Natural gas (dollars per thousand cubic feet)

   —    1.71   1.95    1.28 

 

 

ConocoPhillips

($MM)
$
102
(86)
112
(195)
Average Net Production
Crude oil (MBD)
9
5
10
4
Natural gas liquids (MBD)
4
2
4
1
Bitumen (MBD)
68
34
69
50
Natural gas (MMCFD)
84
40
87
30
Total Production
(MBOED)
95
48
98
60
Average Sales Prices
Crude oil ($ per bbl)
$
56.87
8.69
51.66
15.39
Natural gas liquids ($ per bbl)
27.14
1.64
26.19
1.89
Bitumen ($ per bbl)
37.60
(23.11)
34.09
(3.09)
Natural gas ($ per MCF)
2.26
0.79
2.32
1.05
Average sales prices include unutilized transportation costs.
Our Canadian operations mainly consist of anthe
Surmont oil sands development in Alberta
and the Athabasca Region of northeastern Alberta and a liquids-rich
Montney unconventional play in western Canada. British Columbia.
As of SeptemberJune 30, 2017,2021, Canada contributed 18
8 percent of our worldwide
consolidated liquids production and 74 percent
of our worldwideconsolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips
Earnings from Canada increased by $594$188 million
and $307 million,
respectively, in the third quarter three-
and $3,390 million in the nine-month periodsix-month
periods of 2017. 2021.
Earnings increased in the third quarter primarily due to an additionalafter-tax gain of $190 million for funds received in relation to environmental claims from our Canadawere positively impacted by:
●
Higher realized bitumen and crude oil prices.
●
After-tax gains on disposition discussed below, and lower DD&A mainly due to disposition impacts. Additionally, reduced exploration expenses including the absence of 2016 dry hole costs for the Cheshire well in Nova Scotia; a $114 million tax benefit

related to our prior decisioncontingent

payments of $52 million and $72 million
in the
three-
and six-month periods of 2021, respectively, associated with the sale of certain
assets to exit Nova Scotia deepwater exploration; and lowerCVE in
2017.
44
Partly offsetting the increase in earnings was:
●
Higher production and operating expenses further improved earnings. The third-quarter earnings increase was partlyprimarily
due to the absence of production curtailment
and
increased Montney production.
●
Higher DD&A expenses primarily driven
by higher production volumes partially offset by lower equity earningsrates
from price-related reserve revisions.
●
Absence of a $48 million refund from the disposition of our nonoperated interest in the FCCL Partnership.

In the nine-month period of 2017, earningsAlberta

Tax & Revenue Administration.
Production
Average production increased mainly due to anafter-tax gain of $1.6 billion, primarily recognized47 MBOED in the second quarter on the sale of certain Canadian assets, further discussed below. The first-quarter 2017 recognition of $996 million in deferred tax benefits related to the capital gains component of our disposition 2021
and the recognition of previously unrealizable Canadian tax basis also increased earnings38 MBOED in the nine-month period. Additionally, higher realized prices across all commodities and lower volumes from the disposition of our western Canada gas assets impacted earnings in both periods.

Total average production decreased 78 percent in the third quarter and 33 percent in the nine-monthsix-

month period of 2017. 2021, respectively.
The production decrease in both periodsincrease was primarily due to:
●
Absence of curtailments at our Surmont operated
asset.
●
Wells online from Pad 2 and 3 in the Montney.
●
Production from our Kelt acquisition in the third
quarter of 2020.
●
Improved well performance at our Surmont operated
asset.
Europe, Middle East and North Africa
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
*
2021
2020
*
Net Income Attributable to ConocoPhillips
($MM)
$
207
25
360
226
Consolidated Operations
Average Net Production
Crude oil (MBD)
120
75
118
84
Natural gas liquids (MBD)
4
5
4
5
Natural gas (MMCFD)
297
264
303
287
Total Production
(MBOED)
173
124
172
137
Average Sales Prices
Crude oil ($ per bbl)
$
66.34
32.32
62.48
44.70
Natural gas liquids ($ per bbl)
39.49
16.76
38.21
18.75
Natural gas ($ per MCF)
7.17
2.21
6.58
3.03
*Prior periods have been updated to reflect the Middle East Business Unit
moving from Asia Pacific to the Canada disposition, partly offset by productionramp-up at Surmont.

Asset Disposition Update

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. Europe, Middle East and North Africa

segment.
The Europe,
Middle East and North Africa segment consists
of operations principally located in the Norwegian and U.K. sectors
sector of the North Sea and the Norwegian Sea,
Qatar, Libya and Libya. commercial operations in the U.K.
As of September
June 30, 2017,2021, our Europe,
Middle East and North Africa operations contributed 17
12 percent of our worldwide
consolidated liquids production and 14 percent
of our worldwideconsolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips
Earnings forfrom Europe,
Middle East and North Africa operations decreasedincreased by $78
$182 million and $134 million in the third quarter butthree-
and six-month periods of 2021, respectively.
Earnings were positively impacted by:
●
Higher realized natural gas, crude oil and NGL
prices.
●
Higher LNG sales prices, reflected in equity in
earnings of affiliates.
45
Partly offsetting the increase in earnings was:
●
Higher taxes.
●
Higher DD&A expenses and production and operating
expenses.
●
Absence of foreign currency gains.
Consolidated Production
Average consolidated production increased by $247 million49 MBOED and 35 MBOED in the nine-month period three-
and six-month periods
of 2017. 2021, respectively.
The earnings decrease in the third quarterproduction increase was primarily due:
●
Higher production in Libya due to the absence
of a 2016 net deferred tax benefitforced shutdown of $138the Es Sider export terminal
and other eastern export terminals after
a period of civil unrest.
●
Improved well performance in Norway.
●
New production from Norway drilling activities
including the completion of our Tor II redevelopment
project first achieved in December 2020.
Partly offsetting the increase in production was:
●
Normal field decline.
Asia Pacific
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
*
2021
2020
*
Net Income Attributable to ConocoPhillips
($MM)
$
175
648
492
920
Consolidated Operations
Average Net Production
Crude oil (MBD)
69
61
70
70
Natural gas liquids (MBD)
-
1
-
2
Natural gas (MMCFD)
358
423
353
522
Total Production
(MBOED)
129
133
129
159
Average Sales Prices
Crude oil ($ per bbl)
$
67.72
27.98
64.01
43.02
Natural gas liquids ($ per bbl)
-
27.90
-
33.21
Natural gas ($ per MCF)
6.32
4.74
6.10
5.45
*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.
The Asia Pacific
segment has operations in China, Indonesia,
Malaysia and Australia.
As of June 30, 2021, Asia
Pacific contributed 7 percent of our consolidated
liquids production and 17 percent of our
consolidated natural
gas production.
46
Net Income (Loss) Attributable to ConocoPhillips
Earnings decreased $473 million resulting from a change in the U.K. tax rate enacted second
quarter of 2021 and decreased $428 million
in September 2016. Thethe six-month
period of 2021,
respectively.
Earnings were negatively impacted by:
●
Absence of a $597 million after-tax gain related
to our Australia-West divestiture.
●
Lower earnings due to our Australia-West divestiture completed in the second quarter
of 2020.
●
Higher taxes associated with higher production and
prices in Malaysia and Indonesia.
Partly offsetting the decrease was partly offset by higherin earnings was:
●
Higher crude oil and natural gas realized pricesprices.
●
Lower production and lower DD&A, mainly due operating expenses related
to reserve revisions.

our Australia-West divestiture.

In addition to the factors discusseditems detailed above, earnings increased in the nine-month six-month
period of 2021, earnings also decreased due
to:
●
Lower equity in earnings of affiliates, primarily due to lower proved property impairments
LNG lagging contract prices, partly offset
by increased LNG sales volumes.
In addition to the items detailed above, in the United Kingdom; a $41 million tax benefit in Norway, recognized in the second quarter of 2017; and lower production and operating expenses.

Average production increased 16 percent in the third quarter and nine-month six-month

period of 2017. The increase in the third quarter was mainly2021, earnings also increased due to:
●
A $200 million gain on disposition related
to a FID bonus from our Australia-West divestiture.
For
additional information related to this FID bonus,
see
and
●
Lower exploration expenses, due to the resumptionabsence
of an unproved property impairment andramp-up of dry hole
expenses related to the Kamunsu East Field in Malaysia.
Consolidated Production
Average consolidated production in Libya; new production from the Greater Britannia Areadecreased 4 MBOED and Norway; lower unplanned downtime; higher Norway gas offtake; and improved drilling and well performance in Norway. In addition to these factors, lower planned downtime in Norway improved production30 MBOED in the nine-month period. three-
and six-month periods of
2021, respectively.
The production increase in both periods was partly offset by normal field decline in Norway and the United Kingdom.

Asia Pacific and Middle East

                                                        
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017   2016  2017  2016 
  

 

 

  

 

 

 

Net Income (Loss) Attributable to ConocoPhillips(millions of dollars)

  $396    (87)   (1,540)   (20) 

 

 

Average Net Production

      

Crude oil (MBD)

      

Consolidated operations

   97    100   93   98 

Equity affiliates

   14    15   14   14 

 

 

Total crude oil

   111    115   107   112 

 

 

Natural gas liquids (MBD)

      

Consolidated operations

   4    8   5   8 

Equity affiliates

   8    8   7   8 

 

 

Total natural gas liquids

   12    16   12   16 

 

 

Natural gas (MMCFD)

      

Consolidated operations

   690    712   673   737 

Equity affiliates

   1,040    948   997   883 

 

 

Total natural gas

   1,730    1,660   1,670   1,620 

 

 

Total Production(MBOED)

   411    408   397   398 

 

 

Average Sales Prices

      

Crude oil (dollars per barrel)

      

Consolidated operations

  $52.06    44.27   51.73   40.33 

Equity affiliates

   52.29    44.78   52.87   41.94 

Total crude oil

   52.10    44.34   51.88   40.53 

Natural gas liquids (dollars per barrel)

      

Consolidated operations

   35.74    25.84   38.28   27.66 

Equity affiliates

   35.94    25.12   37.59   27.25 

Total natural gas liquids

   35.86    25.50   37.84   27.46 

Natural gas (dollars per thousand cubic feet)

      

Consolidated operations

   4.63    4.42   4.87   4.20 

Equity affiliates

   4.51    2.90   4.28   2.90 

Total natural gas

   4.56    3.55   4.52   3.50 

 

 

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Brunei. As of September 30, 2017, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 49 percent of our worldwide natural gas production.

Earnings increased by $483 million in the third quarter and decreased by $1,520 million in the nine-month period of 2017.    The earnings increase in the third quarterdecrease was primarily due to higher realized prices across all commodities and the absence of a third-quarter 2016 deferred tax charge of $174 million resulting from the changeto:

●
The divestiture of our APLNG tax functional currency. Additionally, earnings were improved due to an $83 million reduction to a potential tax liability.

Earnings decreasedAustralia-West assets that contributed 24 MBOED in the nine-month period primarily due to a $2,384 million before-second

quarter andafter-tax charge for the impairment of our APLNG investment 35
MBOED in the second quartersix-month period of 2017.

See2020.

●
Normal field decline.
Partly offsetting the “APLNG” sectiondecrease in production was:
●
Absence of Note 5—Investments, Loanscurtailments in Malaysia.
●
Bohai Bay development activity in China.
●
Increased production in Malaysia associated
with Malakai Phase 2 first production and Long-Term Receivables, in the Notesramp-up.
Other International
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Net Income (Loss) Attributable to Consolidated Financial Statements, for information on the impairment of our APLNG investment.

Average production was essentially flat in the third quarter and nine-month period.

Other International

                                                        
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Net Loss Attributable to ConocoPhillips(millions of dollars)

  $(20)   (47)   (77)   (100) 

 

 

ConocoPhillips

($MM)
$
(5)
(6)
(9)
22
The Other International segment consists of exploration
and appraisal activities in Colombia and Chile.

LossesArgentina as

well as contingencies associated with prior operations
in other countries.
Earnings from our Other International operations
increased $1 million and decreased $27$31 million
in the third quarter three-
and $23 millionsix-month periods of 2021, respectively.
The decrease in the nine-month period of 2017. The reduction in losses in the third quarterearnings was primarily due to the absence
of 2016 rig stacking costs in Angola.

Ina

$29 million after-tax benefit to earnings from the nine-month period
dismissal of 2017, losses decreased duearbitration related to lower rig stacking costs in Angola and reduced general and administrative expense prior operations
in Senegal partly offset by a $28 millionafter-tax charge for the cancellation of our Athena drilling rig contract
recognized in the first quarter of 2017.

Exploration Update

In July 2017, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A. executed an Additional Contract for the exploration and exploitation of unconventional reservoirs in an area identified as theVMM-2 Block. As a result, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A. also executed a joint operating agreement. We have an 80 percent operated working interest in the block.

2020.

47
Corporate and Other

                                                        
   Millions of Dollars 
   Three Months Ended
September 30		  Nine Months Ended
September 30		 
   2017  2016  2017  2016 
  

 

 

  

 

 

 

Net Loss Attributable to ConocoPhillips

     

Net interest

  $(176)   (258)   (603)   (714) 

Corporate general and administrative expenses

   (56)   (54)   (213)   (211) 

Technology

   20   44   29   66 

Other

   (115)   (55)   (312)   (72) 

 

 
  $(327)   (323)   (1,099)   (931) 

 

 

Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2021
2020
2021
2020
Net Income (Loss) Attributable to ConocoPhillips
Net interest expense
$
(181)
(174)
(451)
(329)
Corporate general and administrative expenses
(65)
(90)
(194)
(40)
Technology
(4)
(9)
37
(8)
Other income (expense)
316
458
553
(1,213)
$
66
185
(55)
(1,590)
Net interest expense consists of interest and financing
expense, net of interest income and capitalized
interest.
Net interest decreasedexpense increased by $82$7 million
and $122 million in the third quarter and $111 million in the nine-month period of 2017, compared with the same three-and six-month
periods of 2016, primarily due to impacts from the fair market value method of apportioning interest expense in the United States and lower interest on debt expense in the third quarter of 2017, partly offset by lower capitalized interest on projects.

Corporate general and administrative expenses increased by $2 million in the third quarter and nine-month period of 2017, compared with the same periods of 2016,2021,

respectively, primarily due to higher costs from certaindebt balances assumed due to our Concho
acquisition.
Corporate G&A expenses include compensation
programs and staff costs.
These expenses decreased by $25
million in the leasethree-month period of an office building, partly offset2021 primarily
due to mark to market adjustments associated
with certain
compensation programs.
For the six-month period of 2021, Corporate
G&A expenses increased by lower pension settlement expense.

$154

million primarily due to restructuring expenses
associated with our Concho acquisition.
Technology includes our investment in new technologies or businesses, as well
as licensing revenues received. revenues.
Activities are focused on both conventional and tight
oil reservoirs, shale gas, heavy oil, and oil
sands, enhanced
oil sands,recovery, as well as LNG.
Earnings from Technology decreased $24increased $45 million in the third quarter and $37 million in the nine-monthsix-month period of 2017,
2021 primarily due to lowerhigher licensing revenues, partly offset by reduced technology program spend.

The categoryrevenues.

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, and premiums
incurred on the early retirement of debt. “Other” expenses increaseddebt, holding
gains or
losses on equity securities, and pension settlement
expense.
“Other” decreased by $60$142 million in the third second
quarter and $240 million in the nine-month period of 2017. The expense increase in the third quarter was mainly2021, primarily due to a tax liability based on an updated assessment and premiumsafter-tax
gain of $418 million on our early retirement of debt, partly offset by lower restructuring charges. Premiums incurred on our retirement of debt CVE common shares
in the second
quarter further increased expenses of 2021
compared with an after-tax gain of $551 million
in the nine-month period.

same period of 2020 as well as the

absence of the release of a $92 million deferred
tax asset related to our Australia-West divestiture in the second
quarter of 2020.
In the six-month period of 2021, “Other”
increased by $1,766 million,
primarily due to an
after-tax gain of $726 million on our CVE common
shares in the six-month period of 2021, and
the absence of
a $1,140 million after-tax loss on those shares
in the six-month period of 2020.
48
CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

                            
   Millions of Dollars 
   September 30
2017		  December 31
2016		 
  

 

 

 

Short-term debt

  $1,331   1,089 

Total debt

   21,004   27,275 

Total equity

   30,712   35,226 

Percent of total debt to capital*

   41%   44 

Percent of floating-rate debt to total debt

   5%   9 

 

 

Millions of Dollars
June 30
December 31
2021
2020
Cash and cash equivalents
$
6,608
2,991
Short-term investments
2,251
3,609
Total debt
20,010
15,369
Total equity
44,276
29,849
Percent of total debt to capital*
31
%
34
Percent of floating-rate debt to total debt
5
%
7
*Capital includes total debt and total equity.

To meet our short-
and long-term liquidity requirements, we look
to a variety of funding sources, including
cash generated from operating activities, proceeds from asset sales,
our commercial paper and credit facility programs,
and our ability to
sell securities using our shelf registration
statement.
During the first ninesix months of 2017,2021, the primary uses
of
our available cash were $6,594$2,465 million to reduce debt, $3,074 million to support
our ongoing capital expenditures and investments program, $2,583
program;
$1,171 million net purchasesto pay dividends,
approximately $1.0 billion of short-term investments, $2,045hedging, transaction
and restructuring costs,
and $981 million to repurchase common stock, $986 million to pay dividends, and a $600 million contribution to our domestic qualified pension plan. In the first nine months of 2017, we fully prepaid the remaining $1.45 billion balance on our term loan due in 2019 and reduced various debt instruments and notes by $4.8 billion. stock.
During the first ninesix months of 2017,2021, our cash and
cash
equivalents increased by $3,617 million to
$6,608 million.
At June 30, 2021, we had cash and cash equivalents increased by $3.3
of $6.6 billion, to $6.9 billion.

short-term investments of $2.3

billion, and
available borrowing capacity under our credit facility
of $5.7 billion, totaling over $14
billion of liquidity.
We
believe current cash balances and cash generated
by operations, together with access to
external sources of
funds as described below in the “Significant Sources ofChanges
in Capital” section, will be sufficient to meet our
funding
requirements in the nearnear- and long term,long-term, including our capital
spending program, dividend payments and
required debt payments.

Significant Sources ofChanges in Capital

Operating Activities

Cash provided by operating activities was $4,596 $6,331
million for the first ninesix months of 2017,2021, compared
with $2,960
$2,262 million for the corresponding period of 2016. 2020.
The increase was in cash provided by operating activities
is
primarily due to higher realized commodity prices across
and higher sales volumes mostly due to our acquisition
of
Concho.
The increase in cash provided by operating activities
was partly offset by the settlement of all commodities.

Whileoil and

gas hedging positions acquired from Concho,
normal field decline, transaction and restructuring
costs, and the stability
divestiture of our cash flows from operating activities benefits from geographic diversity, ourAustralia-West assets.
Our short-
and long-term operating cash flows are highly
dependent upon prices for crude oil, bitumen, natural
gas, LNG and natural gas liquids. 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.

49
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
Future
production is subject to numerous uncertainties, including,
among others, the volatile crude oil and natural
gas
price environment, which may impact investment
decisions; the effects of price changes on production
sharing
and variable-royalty contracts; acquisition and disposition
of fields; field production decline rates; new
technologies; operating efficiencies; timing of startups
and major turnarounds; political instability;
impacts of
a global pandemic; 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. As
See the
“Capital Expenditures and Investments” section,
for information about our capital expenditures
and
investments.
On January 15, 2021, we undertake cash prioritization efforts,assumed financial derivative
instruments consisting of oil and natural gas
swaps in
connection with our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves.

Investing Activities

Proceedsacquisition of Concho.

At March 31, 2021, all oil and natural gas derivative
financial
instruments acquired from asset sales forConcho were contractually
settled.
In the first ninesix months of 2017 were $13.72021, we paid $761
million relating to these settlements.
Investing Activities
For the first six months of 2021, we invested $2.5
billion in capital expenditures.
Our 2021 operating plan
capital expenditures is currently expected to be
$5.3 billion compared with $419 million $4.7 billion
in 2020.
See the
“Capital Expenditures and Investments” section,
for the corresponding periodinformation about our capital expenditures
and
investments.
We completed our acquisition of 2016. All cash deposits and proceeds from asset dispositions are includedConcho on January 15, 2021.
The assets acquired in the “Cash Flows From Investing Activities” section transaction included
$382 million of cash.
In May 2021, we announced a paced monetization
of our consolidated statementinvestment in CVE common shares with
the plan to
direct proceeds toward our existing share repurchase
authorization program.
We expect to fully dispose of cash flows.

On May 17, 2017,our

CVE shares by year-end 2022, however, the sales pace will
be guided by market conditions, and we completedretain
discretion to adjust accordingly.
In the salesecond quarter of 2021, we sold 20 million
of these shares,
representing approximately 10% of the shares held
at December 31, 2020, for $180 million
of proceeds.
We invest in short-term investments as part of our 50 percent nonoperated interest incash investment strategy, the FCCL Partnership,primary objective of which is
to protect principal, maintain liquidity and provide
yield and total returns; these investments include
time
deposits, commercial paper, as well as debt securities classified
as available for sale.
Funds for short-term
needs to support our operating plan and provide resiliency
to react to short-term price volatility are invested
in
highly liquid instruments with maturities within
the majority of our western Canada gas assetsyear.
Funds we consider available to Cenovus Energy. Consideration formaintain resiliency
in longer term price downturns and to capture
opportunities outside a given operating plan
may be invested in
instruments with maturities greater than one year.
Investing activities in the transaction included $11 billion in cash after customary adjustments and 208 million Cenovus Energy common shares. We have agreed not to transfer any of our Cenovus Energy common shares untilfirst six months from the closing date, after which we intend to decrease our investment over time through market transactions, private agreements or otherwise.

On July 31, 2017, we completed the sale of our interests in the San Juan Basin to an affiliate2021

included net sales of Hilcorp Energy Company. As$1,302 million of September 30, 2017, the total proceeds for the sale was $2.5 billion in cash after customary adjustments. On September 29, 2017, we completed the saleinvestments.
We sold
$1,403 million of our interest in the Panhandle assets for $178short-term instruments
and invested $101 million in cash after customary adjustments.

On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnettlong-term instruments.

50
Financing Activities
We have a revolving credit facility totaling $6.75$6.0 billion, expiring in June 2019. 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 programs. 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
certain designated banks in the United States. U.S.
The facility agreement calls for commitment
fees on available, but
unused, amounts.
The facility agreement also contains early termination
rights if our current directors or their
approved successors
cease to be a majority of the Board of
Directors.

As

The revolving credit facility supports ConocoPhillips
Company’s ability to issue up to $6.0 billion of September 30, 2017, we had two
commercial paper programs. The ConocoPhillips $6.25 billion commercial paper program is available to fund short-term working capital needs. We also have the ConocoPhillips Qatar Funding Ltd. $500 million commercial paper program, which is used to fund commitments relating to QG3. paper.
Commercial paper maturities are generally
limited to 90 days. We had no commercial paper outstanding at September 30, 2017 or December 31, 2016, under the ConocoPhillips nor the ConocoPhillips Qatar Funding Ltd. commercial paper program. We had no direct borrowings or letters
With $300 million of credit issued under the revolving credit facility. Since we had no
commercial paper outstanding and had issued no direct borrowings
or letters of credit, we had access to $6.75$5.7 billion in
available
borrowing capacity under ourthe revolving credit facility
at SeptemberJune 30, 2017.

2021.

We may consider issuing additional
commercial paper in the future to supplement our
cash position.
On January 15, 2021, we completed the acquisition
of Concho in an all-stock transaction.
In the first quarter acquisition,
we assumed Concho’s publicly traded debt, which was recorded at fair value
of 2017,$4.7 billion on the acquisition
date.
In June 2021, we reaffirmed our commitment to preserving
our ‘A’-rated balance sheet with the intent to
reduce gross debt by $5 billion over the next five
years, driving a more resilient and efficient
capital structure.
In January 2021, Fitch affirmed its rating of our long-term
debt as “A” with a “stable” outlook and Standard & Poor’s reflected an improvement in their outlook foraffirmed its
rating of our short-term debt as “F1+.” On January
25, 2021, S&P revised its industry risk
assessment of the
E&P industry to “Moderately High” from “Intermediate”
based on a view of increasing risks from the energy
transition, price volatility, and weaker profitability.
On February 11, 2021, S&P downgraded its rating of our
long-term debt from “negative”“A” to “A-” with a “stable”
outlook and downgraded its rating of
our short-term debt
from “A-1” to “A-2.”
In May 2021, Moody’s affirmed its rating of our senior long-term debt rating atof
“A-.” After improving their outlook forA3” with a
“stable” outlook.
Moody’s rates our short-term debt from “negative” to “positive” in the first quarter of 2017, Moody’s Investor Services upgraded our long-term debt rating from “Baa2” to “Baa1” with a stable outlook in the third quarter in response to our debt reduction. as “Prime-2.”
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 upon
downgrade of our credit rating. ratings.
If our credit rating wereratings are downgraded from their
current levels, it could
increase the cost of corporate debt available to
us and restrict our access to the commercial
paper markets.
If
our credit rating were to deteriorate to a level
prohibiting us from accessing the commercial
paper market, we
would still be able to access funds under our revolving
credit facility.

Certain of our project-related contracts, commercial
contracts and derivative instruments contain
provisions
requiring us to post collateral.
Many of these contracts and instruments permit
us to post either cash or letters
of credit as collateral.
At SeptemberJune 30, 20172021 and December 31, 2016, 2020,
we had direct bank letters of credit of $286 $222
million and $304$249 million, respectively, which secured performance obligations
related to various purchase
commitments incident to the ordinary conduct of
business.
In the event of credit ratings downgrades, we
may
be required to post additional letters of
credit.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC)SEC under which
we as a well-known seasoned issuer, have the ability to issue
and sell an indeterminate amount of various types
of debt and equity securities.

Off-Balance Sheet Arrangements

As part

51
Guarantor Summarized Financial Information
We have various cross guarantees among our Obligor group; 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 our normal ongoing business operationsBurlington Resources
LLC, with respect to its publicly held debt
securities.
Similarly,
ConocoPhillips has fully and consistent unconditionally
guaranteed the payment obligations of ConocoPhillips
Company
with normal industry practice, we enter into numerous agreementsrespect to its publicly held debt securities.
In addition, ConocoPhillips Company
has fully and
unconditionally guaranteed the payment obligations
of ConocoPhillips with other partiesrespect to pursue business opportunities, which share costsits publicly
held debt
securities.
All guarantees are joint and apportion risks amongseveral.
The following tables present summarized financial
information for the partiesObligor Group, as governed bydefined
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 agreements.

For information about guarantees, see Note 11—Guarantees,collective

guarantors and issuers of guaranteed securities
are reflected in the Notesbalances of the summarized
financial information.
●
Non-Obligated Subsidiaries are excluded
from the presentation.
Upon completion of the Concho acquisition
on January 15, 2021, we assumed Concho’s publicly traded debt
of approximately $3.9 billion in aggregate principal
amount, which was recorded at fair value
of $4.7 billion
on the acquisition date.
We completed a debt exchange offer that settled on February 8, 2021, of which 98
percent, or approximately $3.8 billion in aggregate
principal amount of Concho’s notes, were tendered and
accepted for new debt issued by ConocoPhillips.
The new debt issued in the exchange is fully
and
unconditionally guaranteed by ConocoPhillips
Company.
Both the guarantor and issuer of the exchange debt
is reflected within the Obligor Group presented
here.
See
and
for additional information
relating to Consolidated Financial Statements, which is incorporated herein by reference.

the Concho transaction.

Transactions and balances reflecting activity between the Obligors
and Non-Obligated Subsidiaries are
presented below:
Summarized Income Statement Data
Millions of Dollars
Six Months Ended
June 30, 2021
Revenues and Other Income
$
13,054
Income (loss) before income taxes
3,138
Net income (loss)
3,073
Net Income (Loss) Attributable to ConocoPhillips
3,073
52
Summarized Balance Sheet Data
Millions of Dollars
June 30
December 31
2021
2020
Current assets
$
10,597
8,535
Amounts due from Non-Obligated Subsidiaries, current
585
440
Noncurrent assets
58,272
37,180
Amounts due from Non-Obligated Subsidiaries, noncurrent
8,326
7,730
Current liabilities
5,322
3,797
Amounts due to Non-Obligated Subsidiaries, current
2,004
1,365
Noncurrent liabilities
25,829
18,627
Amounts due to Non-Obligated Subsidiaries, noncurrent
7,526
3,972
Capital Requirements

For information about our capital expenditures
and investments, see the “Capital Expenditures”Expenditures
and
Investments” section.

Our debt balance at SeptemberJune 30, 2017,2021, was $21 $20.0
billion, a decrease of $6.3compared with $15.4 billion from the balance at December
31, 2016.

2020.

The
net increase is primarily due to $4.7 billion of
debt assumed in the Concho acquisition.
The current portion of
debt, including payments for finance leases, is
$1,205 million.
Payments will be made using current cash
balances and cash generated by operations.
We believe in delivering value to our shareholders through a growing and sustainable
dividend supplemented
by additional returns of capital, including share repurchases.
In 2020, we paid $1.8 billion, equating to $1.69
per share of common stock, in dividends.
We anticipate returning $2.3 billion to shareholders in the form of
dividends in 2021.
In the first quartersix months of 2017,2021, we made a prepaymentpaid
dividends totaling $1.2 billion, the equivalent of $805 million on our floating rate term loan facility due in 2019. In the third quarter of 2017, we prepaid the remaining balance of $645 million.

We redeemed $4.8 billion of debt during the nine-month period ending September 30, 2017 as described below.

In the second quarter of 2017, we redeemed $3.0 billion of debt across the following instruments:

6.65% Debentures due 2018 with principal of $297 million.

5.75% Notes due 2019 with principal of $2.25 billion (partial redemption of $1.7 billion).

6.00% Notes due 2020 with principal of $1.0 billion.

In the third quarter of 2017, we redeemed $1.8 billion of debt across the following instruments:

5.20% Notes due 2018 with principal of $500 million.

1.50% Notes due 2018 with principal of $750 million.

5.75% Notes due 2019 with principal of $550 million.

We incurred premiums above book value to redeem the debt instruments of $234 million and $50 million in the second and third quarter of 2017, respectively. These costs are reported in the “Other expense” line on our consolidated income statement.

In October 2017, we gave notice to make a partial redemption of $250 million on the $1.25 billion 4.20% Notes due in 2021. The prepayment will occur in the fourth quarter of 2017, and we expect to incur approximately $20 million in premiums above book value, subject to pricing related to this redemption when paid.

On a longer-term basis our debt target is less than $20 billion byyear-end 2017 and $15 billion byyear-end 2019. For more information on Debt, see Note 9—Debt, in the Notes to Consolidated Financial Statements.

Purchase obligations, which are contractual obligations primarily related to market-based contracts in our commodity business and agreements to access and utilize the capacity of third-party equipment and facilities, are expected to be $5 billion for the full year of 2017.

In January 2017, we announced a 6 percent increase in the quarterly dividend to $0.265$0.86 per share. The dividend was paid March 1, 2017, to stockholders of record at the close of business on February 14, 2017. In May 2017,On July 13, 2021, we announced

a quarterly dividend of $0.265 per share. The dividend was paid on June 1, 2017, to stockholders of record at the close of business on May 15, 2017. On July 12, 2017, we announced a quarterly dividend of $0.265 per share. The dividend was paid September 1, 2017, to stockholders of record at the close of business on July 24, 2017.On October 6, 2017, we announced a quarterly dividend of $0.265$0.43 per share, payable December 
September
1, 2017, to stockholders of record at the close of business on October 16, 2017.

On November 10,2021.

In late 2016, we initiated our Board of Directors authorized the purchase of up current share repurchase
program, which has a total program authorization
to $3
repurchase $25 billion of our common stock overstock.
As of June 30, 2021, our plan is to repurchase approximately
$3.5 billion in 2021 and we anticipate funding
approximately $1.0 billion of that amount
through proceeds
from the next three years. Duringsales of our CVE common stock.
The pace of CVE share sales will be guided
by market conditions,
and we retain the first quarter of 2017, our Board of Directors approved an increase indiscretion to adjust accordingly.
In the existing share repurchase authorization to a total of $6 billion, with an expectation of $3 billion occurring in 2017 and the remaining $3 billion allocated to 2018 and 2019. Since our share repurchase program began in November 2016,six months ended June 30, 2021, we have repurchased 47.4
17.7 million shares at a cost of $2.2 billion through September 30, 2017.

During$981 million, $159

million of which was funded using CVE share
proceeds.
Since the third quarterinception of 2017,the program, we madehave repurchased
206 million shares at a $600 million contributioncost of $11.5 billion.
Our dividend and share repurchase programs are
subject to numerous considerations, including
market
conditions, management discretion and other factors.
See “Item 1A—Risk Factors – Our ability to declare
and
pay dividends and repurchase shares is subject to
certain considerations” in Part I—Item
1A in our domestic qualified pension plan, which is included in the “Other” line in the “Cash Flows From Operating Activities” section of our consolidated statement of cash flows. This additional contribution mitigates the need for contributions in future quarters. It also significantly lowers our domestic pension deficit which will reduce future premiums charged by the Pension Benefit Guaranty Corporation.

2020

Annual Report on Form 10-K.
53
Capital Expenditures

                            
   Millions of Dollars 
   Nine Months Ended
September 30		 
   2017   2016 
  

 

 

   

 

 

 

Alaska

  $636    702 

Lower 48

   1,234    992 

Canada

   180    553 

Europe and North Africa

   657    801 

Asia Pacific and Middle East

   316    700 

Other International

   17    81 

Corporate and Other

   34    41 

 

 

Capital expenditures and investments

  $3,074    3,870 

 

 

and Investments

Millions of Dollars
Six Months Ended
June 30
2021
2020
Alaska
$
463
732
Lower 48
1,480
1,130
Canada
68
142
Europe, Middle East and North Africa
257
251
Asia Pacific
148
188
Other International
18
63
Corporate and Other
31
19
Capital expenditures and investments
$
2,465
2,525
During the first ninesix months of 2017,2021, capital expenditures
and investments supported key exploration and
development programs, primarily:

Oil

●
Development and natural gas development and explorationappraisal activities
in the Lower 48, includingprimarily Permian, Eagle Ford, Bakken, and the Permian Basin.

Bakken.

●

Appraisal and development activities
in Alaska activities related to development in the Western North Slope and development
activities in the Greater Kuparuk Area and the Greater Prudhoe Area.

Development activities, in Europe, including the Greater Ekofisk Area, Clair Ridge, Aasta Hansteen, and Heidrun.

●

Continued oil sands development and appraisal

Appraisal activities in liquids-rich plays and optimization
of oils sands development in Canada.

Appraisal drilling in deepwater Gulf of Mexico.

●

Continued development activities across assets
in Malaysia, Indonesia,Norway.
●
Continued development activities in China, Malaysia
and Australia; appraisal activity in Australia; and exploration activity in Malaysia.

Indonesia.

Full-year guidance for

In February 2021, we announced 2021 operating
plan capital expenditures has been loweredof $5.5 billion.
In June 2021, we
reduced capital guidance to $4.5 billion.

$5.3 billion, recognizing

synergistic savings from our Concho acquisition.
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 minimumlow
end of the range is accrued.
We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we
We accrue receivables for probable insurance or other third-party recoveries. recoveries when applicable.
With respect toincome-tax-related 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.

54
Legal and Commitments, in the Notes to Consolidated Financial Statements.

LegalTax 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. operations,
and other contract disputes.
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.

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 63–65 64–66
of
our 20162020 Annual Report on Form10-K.

We occasionally receive requests for information or notices of potential liability
from the Environmental Protection Agency (EPA)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 SeptemberJune 30, 2017,2021, there
were 1415 sites around the United States U.S.
in which we were identified as a potentially responsible
party under CERCLA
and comparable state laws.

At SeptemberJune 30, 2017,2021, our balance sheet included a total
environmental accrual of $182$188 million,
compared with $247
$180 million at December 31, 2016,2020, for remediation
activities in the United StatesU.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

There

Continuing political and social attention to the
issue of global climate change has been resulted in
a broad range of
proposed or promulgated state, national and international
laws focusing on greenhouse gas (GHG)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 announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)) and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger 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.

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 65–6667–69 of our 20162020 Annual
Report on Form10-K.

NEW ACCOUNTING STANDARDS

In February 2016,

55
Climate Change Litigation
Beginning in 2017, governmental and other entities
in several states in the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU)No. 2016-02, “Leases” (ASUNo. 2016-02), which establishes comprehensive accounting U.S. have filed lawsuits against
oil
and financial reporting requirementsgas 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 leasing arrangements. This ASU supersedes the existing requirements in FASB Accounting Standards Codification (ASC) Topic 840, “Leases,” contamination
and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASUNo. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoptionerosion of the standardLouisiana 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 permitted.    Entities are requireduncertainty
about these claims (both as to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients,scope and apply the provisions of ASUNo. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. We plan to adopt ASUNo. 2016-02 effective January 1, 2019, damages)
and we continue to evaluate our exposure in these
lawsuits.
Company Response to Climate-Related Risks
The company has responded by putting in place
a Sustainable Development Risk Management
Standard
covering the ASU to determineassessment and registering of significant
and high sustainable development risks based
on their
consequence and likelihood of occurrence.
We have developed a company-wide Climate Change Action Plan
with the impactgoal of adoption ontracking mitigation activities
for each climate-related risk included in the corporate
Sustainable Development Risk Register.
The risks addressed in our consolidated financial statementsClimate Change Action
Plan fall into four broad categories:
●
GHG-related legislation and disclosures, accounting policiesregulation.
●
GHG emissions management.
●
Physical climate-related impacts.
●
Climate-related disclosure and systems, business processes,reporting.
Emissions are categorized into three different scopes.
Gross operated scope 1 and internal controls. Whilescope 2 GHG
emissions
help us understand our evaluationclimate transition
risk.
●
Scope 1 emissions are direct GHG emissions
from sources that we own or control.
●
Scope 2 emissions are GHG emissions from
the generation of ASUNo. 2016-02 and related implementation activitiespurchased electricity or
steam that we
consume.
Scope 3 emissions are ongoing,indirect emissions
from sources that we expectneither own nor control.
56
We announced in October 2020 the adoption of a Paris-aligned climate risk framework
with the ASU objective of
implementing a coherent set of choices designed
to facilitate the success of our existing exploration
and
production business through the energy transition.
Given the uncertainties remaining about how the
energy
transition will evolve, the strategy aims to be robust
across a range of potential future outcomes.
The strategy is comprised of four pillars:
●
Targets:
Our target framework consists of a hierarchy of targets, from a long-term
ambition that sets
the direction and aim of the strategy, to a medium-term performance target for GHG emissions
intensity, to shorter-term targets for flaring and methane intensity reductions. These
performance
targets are supported by lower-level internal business
unit goals to enable the company to achieve the
company-wide targets.
We have set a material impacttarget 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
operated
emissions by 2050.
We have joined the World
Bank Flaring Initiative to work towards zero
routine
flaring of gas by 2030.
●
Technology choices: We
expanded our Marginal Abatement Cost Curve process
to provide a broader
range of opportunities for emission reduction
technology.
●
Portfolio choices:
Our corporate authorization process requires
all qualifying projects to include a
GHG price in their project approval economics.
Different GHG prices are used depending on the
region or jurisdiction.
Projects in jurisdictions with existing GHG
pricing regimes incorporate the
existing GHG price and forecast into their
economics.
Projects where no existing GHG pricing
regime exists utilize a scenario forecast from
our consolidated financial statementsinternally consistent World Energy Model.
In this
way, both existing and disclosures. For additional information, see Note 21—New Accounting Standards,emerging regulatory requirements are considered in our decision-making.
The
company does not use an estimated market cost
of GHG emissions when assessing reserves
in
jurisdictions without existing GHG regulations.
●
External engagement:
Our external engagement aims to differentiate ConocoPhillips
within the oil and
gas sector with our approach to managing climate-related
risk.
We are 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 NotesCLC
provides another opportunity for ongoing dialogue
about carbon pricing and framing the issues
in
alignment with our public policy principles.
We also belong to Consolidated Financial Statements.

and fund Americans For Carbon

Dividends, the education and advocacy branch of
the CLC.
57
CAUTIONARY STATEMENT
FOR THE PURPOSES OF THE “SAFE HARBOR”
PROVISIONS OF
THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements
within the meaning of Section 27A of the Securities
Act of
1933 and Section 21E of the Securities Exchange
Act of 1934.
All statements other than statements of
historical fact included or incorporated by reference in
this report, including, without limitation,
statements
regarding our future financial position, business
strategy, budgets, projected revenues, projected costs and
plans, and objectives of management for future operations,
the anticipated benefits of the transaction
between us
and Concho Resources Inc. (Concho), the anticipated
impact of the transaction on the combined company’s
business and future financial and operating results,
the expected amount and the timing of synergies from
the
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,
“believe,” “budget,” “continue,” “could,” “effort,”
“estimate,” “expect,” “forecast,” “intend,” “goal,”
“guidance,” “may,” “objective,” “outlook,” “plan,” “potential,
“potential,” “predict,” “projection,” “seek,” “should,”
“target,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target”“would” and similar expressions.

We based the forward-looking statements on our current expectations, estimates
and projections about
ourselves and the industries in which we operate in
general.
We caution you these statements are not
guarantees of future performance as they involve
assumptions that, while made in good faith,
may prove to be
incorrect, and involve risks and uncertainties
we cannot predict.
In addition, we based many of these forward-lookingforward-
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-lookingforward-
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 natural gas liquidsNGLs prices, including a prolonged
decline
in these prices relative to historical or future
expected levels.

●

The impact of recent, significant declines in prices for
crude oil, bitumen, natural gas, LNG and natural gas liquids, NGLs,
which
may result in recognition of impairment costscharges 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.

Inability to maintain●

Reductions in reserves replacement rates, consistent with prior periods, whether
as a result of the recent, 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 exploration and production facilities.

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 natural gas liquids.

NGLs.

●

Inability to timely obtain or maintain permits,
including those necessary for construction, drilling
and/or development; failure to comply with applicable laws and regulations;development, or inability to make capital
expenditures required to maintain compliance
with
any necessary permits or applicable laws or regulations.

58
●
Failure to complete definitive agreements and feasibility
studies for, and to complete construction of,
announced and future exploration and productionE&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, or infrastructure
and information technology failures,
constraints or disruptions.

●

Changes in international monetary conditions and
foreign currency exchange rate fluctuations.

Reduced demand for●

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 products or the use of competing energy products, including alternative energy sources.

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.

regulations and litigation.

●

Significant operational or investment changes imposed
by existing or future environmental
statutes
and regulations, including international agreements
and national or regional legislation and regulatory
measures to limit or reduce GHG emissions.
●
Liability resulting from litigation.

litigation, including the
potential for litigation related to the
transaction with

Concho, 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 natural gas liquids pricing,NGLs pricing; regulation or taxation;
and other political, economic or diplomatic developments.

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 exploration and production
E&P industry.

●

Any limitations on our access to capital or increase
in our cost of capital, related to including as a result
of
illiquidity or uncertainty in the domestic or international
financial markets.

markets or investment sentiment.

●

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.

Our inability to obtain economical financing for development, construction or modification of facilities and general corporate purposes.

●

The operation and financing of our joint ventures.

●

The ability of our customers and other contractual
counterparties to satisfy their obligations to us.

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 and fully achieve
the expected benefits and
cost reductions associated with the transaction
with Concho in a timely manner or at all.
●
The risk that we will be unable to retain and hire
key personnel.
●
Unanticipated difficulties or expenditures relating to integration
with Concho.
●
Uncertainty as to the long-term value of our common
stock.
●
The diversion of management time on integration-related
matters.
●
The factors generally described in Part I—Item 1A—Risk Factors 1A
in our 20162020 Annual Report on Form
10-K and any
additional risks described in our other filings
with the SEC.

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

59
Item 3.
QUANTITATIVE
AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
Information about market risks for the ninesix months
ended SeptemberJune 30, 2017,2021, does not differ materially
from that
discussed under Item 7A in our 20162020 Annual Report
on Form10-K.

Item 4.CONTROLS AND PROCEDURES

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 Securities and Exchange CommissionSEC 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
At June 30, 2017, 2021,
with the participation of our management, our Chairman
and Chief Executive Officer (principal executive
officer) and our Executive Vice President Finance, Commercial and Chief Financial Officer (principal financial
officer) carried out
an evaluation, pursuant to Rule13a-15(b) of
the Act, of ConocoPhillips’ disclosure controls
and procedures (as
defined in Rule13a-15(e) of the Act).
Based upon that evaluation, our Chairman and
Chief Executive Officer
and our Executive Vice President Finance, Commercial and Chief Financial Officer concluded our disclosure
controls and
procedures were operating effectively as of Septemberat June 30, 2017.

2021.

There have been no changes in our internal
control over financial reporting, as defined
inRule 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

The following is a description of reportable

Item 1.
LEGAL PROCEEDINGS
There are no new material legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the third quarter of 2017 and any
or material developments with respect to
matters previously reported
disclosed in ConocoPhillips’ 2016Item 3 of our 2020 Annual Report on
Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to U.S. Securities and Exchange Commission regulations.

On April 30, 2012, the separation of our downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain or have subsequently become a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.

Matters previously reported—ConocoPhillips

A Judgment and Consent Decree was entered on December 7, 2016, by the South Central Judicial District Court in Burleigh County, North Dakota against Burlington Resources Oil & Gas Company LP and ConocoPhillips Company resolving alleged violations of the state’s air pollution control laws. The North Dakota Department of Health was the Plaintiff in this matter. The Consent Decree requires the companies to implement a specified program to inspect and repair as necessary its facilities in North Dakota and to pay a penalty. The parties agreed to a penalty of $193,100 and the companies paid that amount in the third quarter, resolving this matter.

Matters previously reported—Phillips 66

In October 2016, after Phillips 66 received a Notice of Intent to Sue from Sierra Club, Phillips 66 entered into a voluntary settlement with the Illinois Environmental Agency for alleged violations of wastewater requirements at the Wood River Refinery. The settlement involves certain capital projects and payment of $125,000. After the settlement was filed with the Court for final approval, the Sierra Club sought and was granted approval to intervene in the case. Phillips 66 is working to obtain Court approval for the settlement.

Item 1A.RISK FACTORS

Item 1A.
RISK FACTORS
There have been no material changes from the
risk factors disclosed in Item 1A of our 2016 2020
Annual Report on
Form10-K.

Item 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

60
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**		 

 

 

July1-31, 2017

   6,952,156   $43.61    6,952,156   $4,496 

August1-31, 2017

   7,849,928    44.42    7,849,928    4,147 

September1-30, 2017

   6,899,880    46.14    6,899,880    3,829 

 

 

Total

   21,701,964   $44.71    21,701,964   $3,829 

 

 

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
April 1-30, 2021
2,425,224
$
51.54
2,425,224
$
13,983
May 1-31, 2021
2,933,604
55.35
2,933,604
13,821
June 1-30, 2021
5,313,280
59.86
5,313,280
13,503
10,672,108
10,672,108
*There were no repurchases of common stock from company employees in connection with the company’scompany's broad-based employee incentive plans.

** On November 10,

In late 2016, we announcedinitiated our current share repurchase
program, which has a share repurchasetotal program for up to $3 authorization
of $25
billion of our common stock over the next three years. On March 29, 2017,stock.
In February 2021, we announced plans to doubleresumed our share repurchase
program to $6 an annualized
level of $1.5 billion which was increased in June
to an annualized level of $2.5 billion.
In May 2021, we
announced a plan to dispose of our 208 million
CVE shares by year-end 2022.
The sales pace will be guided
by market conditions, with ConocoPhillips
retaining discretion to adjust accordingly.
The proceeds from this
disposition will be deployed towards incremental
share repurchases.
At June 30, 2021, we had repurchased $11.5
billion of common stock over the next three years. Acquisitions for the share repurchase programshares, with $13.5 billion remaining
under our current
authorization.
Repurchases are made at management’s discretion, at prevailing
prices, subject to market
conditions and other factors. Repurchases
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.

Item 6.EXHIBITS

12*Computation of Ratio of Earnings to Fixed Charges.
31.1*Certification of Chief Executive Officer pursuant to Rule13a-14(a) under the Securities Exchange Act of 1934.
31.2*Certification of Chief Financial Officer pursuant to Rule13a-14(a) under the Securities Exchange Act of 1934.
32*Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*XBRL Instance Document.
101.SCH*XBRL Schema Document.
101.CAL*XBRL Calculation Linkbase Document.
101.LAB*XBRL Labels Linkbase Document.
101.PRE*XBRL Presentation Linkbase Document.
101.DEF*XBRL Definition Linkbase Document.

See the “Our ability to declare and pay dividends
and repurchase shares is
subject to certain considerations” section in Risk
Factors on page 31 of our 2020 Annual Report
on
Form 10-K.
61
Item 6.
EXHIBITS
10.1*
10.2*
31.1*
31.2*
32*
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.

62
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/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

October 31, 2017

62

CONOCOPHILLIPS
/s/ Kontessa S. Haynes-Welsh
Kontessa S. Haynes-Welsh
Chief Accounting Officer
August 5, 2021