Management's

Discussion and Analysis is the company's analysis of its financial performance and of significant trends that may affect future performance.

It should be read in conjunction with the financial statements and notes.

It contains forward-looking statements including, without limitation,



statements relating
to the company's

plans, strategies, objectives, expectations

and intentions that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform

Act of 1995.



The words "anticipate,"
"estimate," "believe," "budget," "continue,"

"could," "intend," "may," "plan," "potential," "predict," "seek," "should," "will," "would," "expect,"

"objective," "projection," "forecast," "goal," "guidance," "outlook," "effort," "target" and similar expressions identify forward-looking statements.



The company does
not undertake to update, revise or correct any of the forward-looking
information unless required to do so
under the federal securities laws.

Readers are cautioned that such forward-looking statements should be read in conjunction with the company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS



OF THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995," beginning on page 59.

The terms "earnings" and "loss" as used in Management's Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.

BUSINESS ENVIRONMENT AND EXECUTIVE

OVERVIEW

ConocoPhillips is an independent E&P company

with operations and activities in 16 countries.



Our diverse,
low cost of supply portfolio includes resource-rich

unconventional plays in North America;

conventional

assets in North America, Europe and Asia; LNG

developments; oil sands assets in Canada;



and an inventory of
global conventional and unconventional exploration

prospects.



At June 30, 2020, we employed approximately
9,700 people worldwide and had total assets

of $63 billion.


Overview

The energy landscape changed dramatically in 2020 with



simultaneous demand and supply shocks that drove
the industry into a severe downturn.

The demand shock was triggered by COVID-19,



which was declared a
global pandemic and caused unprecedented social

and economic consequences.



Mitigation efforts to stop the
spread of this contagious disease included stay-at-home

orders and business closures that caused sharp
contractions in economic activity worldwide.

The supply shock was triggered by disagreements

between

OPEC and Russia, beginning in early

March, which resulted in significant supply coming



onto the market and
an oil price war.

These dual demand and supply shocks caused



oil prices to collapse as we exited the first
quarter.

As we entered the second quarter, predictions of COVID-19 driven global



oil demand losses intensified, with
forecasts of unprecedented demand declines.

Based on these forecasts, OPEC plus nations held



an emergency
meeting, and in April they announced a coordinated

production cut that was unprecedented in both its
magnitude and duration.

The OPEC plus countries agreed to cut production



by 9.7 MMBOD in May and June,
9.6 MMBOD in July, and 7.7 MMBOD from August to December.

From January 2021 to April 2022, they
agreed to cut production by 5.8 MMBOD.

Additionally, non-OPEC plus countries, including the U.S., Canada, Brazil and other G-20 countries,

announced organic reductions to production through the



release of
drilling rigs, frac crews, normal field decline

and curtailments.



Despite these planned production decreases,
the supply cuts were not timely enough to overcome

significant demand decline.



Futures prices for April WTI
closed under $20 a barrel for the first time

since 2001, followed by May WTI settling below zero on the

day

before futures contracts expiry, as holders of May futures contracts struggled to



exit positions and avoid taking
physical delivery.

As storage constraints approached, spot prices in



April for certain North American
landlocked grades of crude oil were in the single digits

or even negative for particularly remote or low-grade crudes, while waterborne priced crudes such as Brent

sold at a relative advantage.

37

Since the start of the severe downturn, we have closely



monitored the market and taken prudent actions in
response to this situation.

We entered the year in a position of relative strength, with cash and cash equivalents of more than $5 billion, short-term investments

of $3 billion, and an undrawn credit facility



of $6 billion,
totaling approximately $14 billion in available

liquidity.

Additionally, we had several entity and asset sales agreements in place, which generated $1.3 billion

in proceeds from dispositions during the first



six-months of
2020.

For more information about the sales of our Australia-West and non-core Lower 48 assets,



see Note 4-
Asset Acquisitions and Dispositions in the

Notes to Consolidated Financial Statements.



This relative
advantage allowed us to be measured in our response

to the sudden change in business environment.

In March, we announced an initial set of actions

to address the downturn and followed up with additional actions in April.

The combined announcements reflected a reduction



in our 2020 operating plan capital of $2.3
billion, a reduction to our operating costs of

$600 million and suspension of our share repurchase

program.

These actions will decrease uses of cash by over

$5 billion in 2020.



We also established a framework for
evaluating and implementing economic curtailments

considering the weakness in oil prices during the

second

quarter of 2020,

which resulted in taking an additional significant



step of curtailing production, predominantly
from operated North American assets.

Due to our strong balance sheet, we were in an advantaged



position to
forgo some production and cash flow in anticipation

of receiving higher cash flows for those volumes



in the
future.

In the second quarter, we curtailed production by an estimated 225 MBOED,



with 145 MBOED of the
curtailments from the Lower 48, 40 MBOED from

Alaska and 30 MBOED from our Surmont operation

in

Canada.

The remainder of the second-quarter curtailments

were primarily in Malaysia.



Other industry
operators also cut production and development plans

and as we progressed through the second quarter, stay-at- home restrictions eased, which partially restored

lost demand, and WTI and Brent prices exited the

second

quarter around $40 per barrel.

While we remain cautious regarding the recent

oil market recovery and continue to monitor



global market
conditions and COVID-19 hotspots around the world,

based on our economic criteria, we restored

curtailed

production in Alaska during July.

We also brought some curtailed volumes in the Lower 48 back online and expect to be fully restored in September.

At Surmont, we began restoring production in



July, though the ramp
will be slower due to planned turnarounds in the

third quarter and limited staffing in the fields as a COVID-19 mitigation measure.

We continue to monitor pricing and evaluate curtailments across our assets on a month- by-month basis.



At June 30, 2020,

we had $12.9 billion of liquidity, comprised of $2.9 billion in cash and



cash equivalents,
$4.0 billion in short-term investments, and an undrawn

credit facility of $6 billion.



On July 8, 2020, we
announced a quarterly dividend of 42 cents per share

to be distributed on September 1, 2020 to shareholders

of

record as of July 20, 2020.

In July 2020, we signed a definitive agreement

to acquire additional Montney acreage for cash



consideration of
approximately $375 million before customary adjustments,

plus the assumption of approximately $30 million
in financing obligations for associated partially

owned infrastructure.



This acquisition consists primarily of
undeveloped properties and includes 140,000

net acres in the liquids-rich Inga Fireweed asset

Montney zone,
which is directly adjacent to our existing Montney

position, as well as 15 MBOED of production.

Upon

completion of this transaction, we will have a Montney



acreage position of 295,000 net acres with a 100
percent working interest.

The transaction is subject to regulatory



approval and is expected to close in the third
quarter of 2020 with an effective date of July 1, 2020.

Our expectation is that commodity prices will

remain cyclical and volatile, and a successful



business strategy
in the E&P industry must be resilient in

lower price environments, at the same time retaining



upside during
periods of higher prices.

While we are not impervious to current market



conditions, our decisive actions over
the last several years of focusing on free cash flow generation,

high-grading our asset base, lowering the cost
of supply of our investment resource base, and strengthening

our balance sheet have put us in a strong relative position compared to our independent E&P peers.

Although recent prices have been extremely volatile,

we

38

remain committed to our core value proposition

principles, namely, to focus on financial returns, maintain a strong balance sheet, deliver compelling returns

of capital, and maintain disciplined capital

investments.

Our workforce and operations have adjusted to

mitigate the impacts of the COVID-19 global

pandemic.

We

have operations in remote areas with confined spaces,

such as offshore platforms, the North Slope of Alaska, Curtis Island in Australia, western Canada and

Indonesia, where viruses could rapidly spread.



Personnel are
asked to perform a self-assessment for symptoms

of illness each day and, when appropriate,



are subject to
more restrictive measures traveling to and working

on location.



Staffing levels in certain operating locations
have been reduced to minimize health risk exposure

and increase social distancing.

A large portion of our office staff have been successfully working remotely, with offices around the world carefully designing

and

executing a flexible, phased reentry, following national, state and local guidelines.



Workforce health and
safety remains the overriding driver for our actions

and we have demonstrated our ability



to adapt to local
conditions as warranted.

These mitigation measures have thus far been effective



at protecting employees'
health and reducing business operation disruptions.

The marketing and supply chain side of our business

has also adapted in response to COVID-19.

Our

commercial organization is managing transportation commitments

considering curtailment measures.

Our

supply chain function is proactively working with

vendors to ensure the continuity of our



business operations,
monitor distressed service and materials providers,

capture deflation opportunities, and pursue cost

reduction

efforts.

Operationally, we remain focused on safely executing the business.



In the second quarter of 2020, production
of 981 MBOED generated cash from operating activities

of $0.2 billion.



We invested $0.9 billion into the
business in the form of capital expenditures and

paid dividends to shareholders of $0.5 billion.

Production

decreased 351 MBOED or 26 percent in the second

quarter of 2020, compared to the second quarter



of 2019,
primarily due to curtailments and the divestiture

of our U.K. assets in the third quarter of 2019, the

divestiture

of our Australia-West business and several non-core assets in the Lower 48 during the



first six-months of
2020, and the declaration of force majeure in Libya

in February 2020.



Excluding Libya, and adjusting for
closed dispositions and estimated curtailments,

production in the second quarter of 2020 was slightly

higher

than the same period a year ago.

In the first half of the year we recognized a $1.1

billion before and after-tax unrealized loss



on our 208 million
Cenovus Energy common shares and $0.4 billion after-tax

in impairments due to low domestic natural

gas

prices.

Persistent low commodity prices may result in



further proved and unproved property impairments,
including to certain equity method investments.

[[Image Removed: COP20202q10qp41i0.gif]]

[[Image Removed: COP20202q10qp41i1.gif]]




39

-

1

2

3

4

20

40

60

80
Q2'18
Q3'18
Q4'18
Q1'19
Q2'19
Q3'19
Q4'19
Q1'20
Q2'20
WTI/Brent
$/Bbl
WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Prices
Quarterly Averages
WTI - $/Bbl
Brent - $/Bbl
HH - $/MMBTU
HH
Business Environment

Commodity prices are the most significant

factor impacting our profitability and related reinvestment

of

operating cash flows into our business.

Among other dynamics that could influence world



energy markets and
commodity prices are global economic health, supply

or demand disruptions or fears thereof caused



by civil
unrest, global pandemics, military conflicts,

actions taken by OPEC plus and other major



oil producing
countries, environmental laws, tax regulations,

governmental policies and weather-related

disruptions.

Our

strategy is to create value through price cycles

by delivering on the financial and operational



priorities that
underpin our value proposition.


Our earnings and operating cash flows generally

correlate with price levels for crude oil



and natural gas, which
are subject to factors external to the company and over

which we have no control.



The following graph depicts
the trend in average benchmark prices for WTI

crude oil, Brent crude oil and Henry Hub natural

gas:

Brent crude oil prices averaged $29.20 per barrel

in the second quarter of 2020,



a decrease of 58 percent
compared with $68.82 per barrel in the second quarter

of 2019.



WTI at Cushing crude oil prices averaged
$27.85 per barrel in the second quarter of 2020,

a decrease of 53 percent compared with $59.80 per



barrel in
the second quarter of 2019.

Oil prices fell significantly as producers failed to



reduce output sufficiently or
timely enough to offset the demand reduction due to COVID-19.


Henry Hub natural gas prices averaged $1.71

per MMBTU in the second quarter of 2020,



a decrease of 35
percent compared with $2.64 per MMBTU in the second

quarter of 2019.

Henry Hub prices decreased due to
high storage levels and weak domestic and LNG feedstock

demand.

Our realized bitumen price averaged negative $23.11 per barrel



in the second quarter of 2020, a decrease of
$60 per barrel compared with $37.20 per barrel

in the second quarter of 2019.



The decrease in the second
quarter of 2020 was driven by lower blend price

for Surmont sales, largely attributed to a weakening

WTI

price and a narrowing spread between the local market

and U.S. sales points, which challenged



both pipeline
and rail economics.

As a result, we curtailed production, and an increasing



portion of remaining blend sales
were directed to the lower priced local market.

In addition, we incurred unutilized transportation



costs which
negatively impacted our realized bitumen price.

Our total average realized price was $23.09 per BOE

in the second quarter of 2020, compared



with $50.50 per
BOE in the second quarter of 2019.



40

Key Operating and Financial Summary

Significant items during the second quarter

of 2020 included the following:




?

Ended the quarter with cash, cash equivalents and

restricted cash totaling $3.2 billion and

short-term


investments of $4.0 billion.
?

Produced 981 MBOED excluding Libya; curtailed



approximately 225 MBOED.
?

Completed the Australia-West divestiture, generating $0.8 billion in proceeds. ?



Distributed $0.5 billion in dividends.
?

In July, announced a planned bolt-on acquisition of adjacent acreage in the liquids-rich

Montney.


Outlook

Capital and Production

In February 2020, we announced 2020 operating

plan capital of $6.5 billion to $6.7 billion.



In response to the
recent oil market downturn, we announced capital

expenditure reductions totaling $2.3 billion.



This does not
include capital for acquisitions.

In July 2020, we announced a planned bolt-on



acquisition in the liquids-rich
area of the Montney for approximately $0.4 billion.

In the second quarter, we curtailed production by an estimated 225 MBOED,



with 145 MBOED of the
curtailments from the Lower 48, 40 MBOED from

Alaska and 30 MBOED from our Surmont operation

in

Canada.

The remainder of the second-quarter curtailments

were primarily in Malaysia.



Prices rebounded off
their second quarter lows, with Brent crude at

the end of June near $40 per barrel, and based



on our economic
criteria, we restored curtailed production in Alaska

during July.



We also brought some curtailed volumes in
the Lower 48 back online and expect to be fully

restored in September.



At Surmont, we began restoring
production in July, though the ramp will be slower due to planned turnarounds in

the third quarter and limited
staffing in the fields as a COVID-19 mitigation measure.

We continue to monitor pricing and evaluate
curtailments across our assets on a month-by-month

basis.

Estimated curtailments for the third quarter of 2020 are 115 MBOED.



Depreciation, Depletion and Amortization
DD&A expense was $1.2 billion in the second quarter

of 2020.



Proved reserves estimates were updated in the
current quarter utilizing trailing twelve-month

oil and gas prices, which increased second



quarter DD&A
expense by approximately $70 million before-tax.

If oil and gas prices persist at depressed levels,



our reserve
estimates may decrease further, which could incrementally increase

the rate used to determine DD&A expense
on our unit-of-production method properties.















41
RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-



and six-month periods ended June 30, 2020, is
based on a comparison with the corresponding periods of 2019.

Consolidated Results

A summary of the company's net income (loss)

attributable to ConocoPhillips by business segment



follows:

Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Alaska
$
(141)
462
(60)
846
Lower 48
(365)
206
(802)
399
Canada
(86)
100
(195)
222
Europe and North Africa
11
407
86
614
Asia Pacific and Middle East
662
517
1,060
1,042
Other International
(6)
81
22
212
Corporate and Other
185
(193)
(1,590)
78
Net income (loss) attributable to ConocoPhillips
$
260
1,580
(1,479)
3,413

Net income attributable to ConocoPhillips

in the second quarter of 2020 decreased $1,320 million.

Earnings

were negatively impacted by:



?

Lower realized commodity prices.
?

Lower sales volumes, primarily due to production

curtailments across our North American

operated

assets and the divestiture of our U.K. assets in

the third quarter of 2019 and Australia-West assets in the second quarter of 2020. ?

The absence of a $234 million U.S. tax benefit

related to the recognition of U.S. tax basis in

our


disposed U.K. subsidiaries.
?

The absence of $115 million benefit related to the settlement



of certain tax disputes and enhanced oil
recovery credits.
?

The release of $92 million of deferred tax assets

in our Corporate segment as a result of the

Australia-
West divestiture.

?

The absence of other income of $84 million after-tax



related to our settlement agreement with
Petróleos de Venezuela, S.A. (PDVSA).


Second quarter 2020 net income decreases were partly

offset by:



?

Higher gain on dispositions primarily due to

a $597 million after-tax gain related to our Australia- West divestiture. ?



A $521

million higher after-tax unrealized gain on our



Cenovus Energy common shares reflected in
other income.
?

Lower production and operating expenses,

primarily due to decreased wellwork and transportation costs associated with production curtailments

across our North American operated assets as well

as

the absence of costs related to our U.K. divestiture. ?

Lower DD&A primarily due to lower volumes related

to production curtailments and the cessation of DD&A related to our Australia-West divestiture, partly offset by higher DD&A rates due to

price-

related downward reserve revisions.





42

Net loss attributable to ConocoPhillips in

the six-month period ended June 30, 2020, decreased

$4,892 million.

Earnings were negatively impacted by:



?

Lower realized commodity prices.
?

Lower sales volumes, primarily due to normal field

decline, production curtailments across our

North

American operated assets and the divestiture of our

U.K. assets in the third quarter of 2019 and our Australia-West assets in the second quarter of 2020. ?

A $1,140 million after-tax unrealized loss on our



Cenovus Energy common shares in the six-month
period of 2020, reflected in other income, as compared

to a $373 million after-tax unrealized gain in
the six-month period of 2019.
?

Higher impairments of $400 million after-tax,

primarily related to non-core gas assets in our Lower

48

segment.


?

The absence of a $234 million U.S. tax benefit

related to the recognition of U.S. tax basis in

our


disposed U.K. subsidiaries.
?

The absence of other income of $231 million after-tax



related to our settlement agreement with
PDVSA.
?

The absence of a $115 million benefit related to the settlement



of certain tax disputes and enhanced oil
recovery credits.
?

The release of $92 million of deferred tax assets

in our Corporate segment as a result of our Australia- West divestiture.

The decreases in earnings in the six-month period



ended June 30, 2020,

were partly offset by:

?

Higher gain on dispositions primarily due to

a $597 million after-tax gain related to our Australia- West



divestiture.
?

Lower production and operating expenses,

primarily due to decreased wellwork and transportation costs associated with production curtailments

across our North American operated assets

as well as the absence of costs related to our U.K. divestiture. ?

Lower DD&A primarily due to lower volumes related

to production curtailments and the cessation

of

DD&A related to our Australia-West divestiture, partly offset by higher DD&A rates due to

price-


related downward reserve revisions.
?

The absence of impairments related to equity method



investments of $120 million after-tax in the
Lower 48, recorded within equity in earnings of affiliates.

See the "Segment Results" section for additional



information.

Income Statement Analysis


Sales and other operating revenues for the three-

and six-month periods of 2020 decreased $5,204



million and
$8,196 million,

mainly due to lower realized commodity prices



and lower sales volumes due to production
curtailments from our North American operated

assets and the divestiture of our U.K. assets



in the third quarter
of 2019 and our Australia-West assets in the second quarter of 2020.


Equity in earnings of affiliates for the three-

and six-month periods of 2020 decreased

$96 million and $50
million primarily due to lower earnings from QG3

and APLNG as a result of lower LNG prices and

sales

volumes for both affiliates and lower oil prices at QG3.

Partly offsetting the decrease in equity in earnings of affiliates were the absence of impairments related

to equity method investments in our Lower 48 segment

of

$95 million in the second quarter of 2019 and $155

million in the six-month period of 2019.















43

Gain on dispositions for the three-

and six-month periods of 2020 increased $514



million and $455 million
primarily due to a $587 million before-tax gain associated

with our Australia-West divestiture.



For more
information, see Note 4-Asset Acquisitions

and Dispositions in the Notes to Consolidated

Financial

Statements.

Other income (loss) for the second quarter of 2020

increased $422 million, primarily due to

$521 million
higher before-tax unrealized gain on our Cenovus

Energy common shares, partly offset by the absence of $89 million before-tax related to our settlement

agreement with PDVSA.



Other income in the six-month period of
2020 decreased $1,819 million, primarily due to a $1.14

billion before-tax unrealized loss on our Cenovus
Energy common shares compared to a $373 million before-tax

unrealized gain on those shares in the six-
month period of 2019 and the absence of $236 million

before-tax related to our settlement agreement

with

PDVSA.

For discussion of our Cenovus Energy shares, see Note



6-Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements.

For discussion of our PDVSA settlement, see Note

12-Contingencies

and Commitments, in the Notes to Consolidated Financial

Statements.

Purchased commodities for the three- and six-month

periods



of 2020 decreased $1,544 million and $2,558
million,

respectively, primarily due to lower crude oil and natural gas volumes purchased

and lower natural gas
and crude oil prices.


Production and operating expenses for the three-

and six-month periods of 2020 decreased $371

million and $469 million, respectively, mainly due to lower costs associated with the divestiture

of our U.K. and Australia- West assets, and decreased production volumes, primarily due to production curtailments,



and lower legal
accruals in our Lower 48 and Other International

segments.

Selling, general and administrative expenses decreased

$129 million in the six-month period of 2020,

primarily

due to lower costs associated with compensation

and benefits, including mark to market



impacts of certain key
employee compensation programs.

DD&A for the three-

and six-month periods of 2020 decreased

$332 million and $467 million, respectively,
mainly due to lower production volumes related to

production curtailments and the divestiture

of our Australia-West and U.K. assets, partly offset by higher DD&A rates due to price-related downward



reserve
revisions.

For more information regarding the Australia-West divestiture, see Note 4-Asset Acquisitions

and

Dispositions in the Notes to Consolidated Financial

Statements.

Impairments increased $517 million in

the six-month period of 2020, primarily due to a $511 million before- tax impairment of certain non-core gas assets in

our Lower 48 segment due to a significant



decrease in the
outlook for natural gas prices.

See Note 8-Impairments in the Notes to Consolidated



Financial Statements,
for additional information.

Foreign currency transaction (gain) loss decreased $123

million in the six-month period of 2020, primarily

due

to gains recognized from foreign currency derivatives.

See Note 13-Derivative and Financial Instruments

in

the Notes to Consolidated Financial Statements,

for additional information.

See Note 21-Income Taxes, in the Notes to Consolidated Financial Statements,



for information regarding our
income tax provision (benefit) and effective tax rate.



























44
Summary Operating Statistics
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Average Net Production
Crude oil (MBD)
474
702
564
708
Natural gas liquids (MBD)
93
118
108
114
Bitumen (MBD)
34
51
50
57
Natural gas (MMCFD)*
2,277
2,768
2,475
2,804
Total Production
(MBOED)
981
1,332
1,135
1,346
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
25.10
64.88
38.80
62.14
Natural gas liquids (per bbl)
9.88
21.65
12.63
22.71
Bitumen (per bbl)
(23.11)
37.20
(3.09)
35.00
Natural gas (per MCF)
3.22
4.76
3.81
5.39
Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical,
lease rental, and other
$
94
81
215
164
Leasehold impairment
-
25
31
42
Dry holes
3
16
39
26
$
97
122
285
232

*Represents quantities available for sale and excludes gas equivalent of natural

gas

liquids included above.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a



worldwide
basis.

At June 30, 2020, our operations were producing

in the U.S., Norway, Canada, Australia, Indonesia, China, Malaysia,

Qatar and Libya.

Total production decreased 351 MBOED or 26 percent in the second quarter of 2020,



primarily due to:

?

Production curtailments, primarily from



our North American operated assets and Malaysia.
?

Normal field decline.
?

The divestiture of our U.K. assets in the third

quarter of 2019, our Australia-West assets in the second quarter of 2020, and non-core Lower 48 assets in



the first quarter of 2020.
?

No production in Libya due to the forced shutdown

of the Es Sider export terminal and other

eastern

export terminals after a period of civil unrest.

The decrease in second quarter 2020 production was

partly offset by:



?

New wells online in the Lower 48, Canada, Norway



and China.




45

Total production decreased 211 MBOED or 16 percent in the six-month period of 2020,



primarily due to:

?

Normal field decline.
?

Production curtailments, primarily from



our North American operated assets and Malaysia.
?

The divestiture of our U.K. assets in the third

quarter of 2019, our Australia-West assets in the second quarter of 2020, and non-core Lower 48 assets in



the first quarter of 2020.
?

Lower production in Libya due to the forced shutdown



of the Es Sider export terminal and other
eastern export terminals after a period of civil unrest

in the first quarter of 2020.

The decrease in production during the six-month period

of 2020 was partly offset by:



?

New wells online in the Lower 48, Norway, Canada and China.

Production excluding Libya was 981 MBOED in

the second quarter of 2020, a decrease of



309 MBOED
compared with the same period of 2019.

Adjusting for closed dispositions and Libya, production

decreased

212 MBOED primarily due to production curtailments

and normal field decline, partly offset by new wells online in the Lower 48, Norway, Canada and China.

Excluding closed dispositions, estimated curtailment impacts of 225 MBOED and Libya, production was

slightly higher compared with the same

period a year ago.

Production excluding Libya was 1,130 MBOED in

the six-month period of 2020, a decrease



of 173 MBOED
compared with the same period of 2019.

Adjusting for closed dispositions and Libya, production



decreased 79
MBOED primarily due to normal field decline

and production curtailments, partly offset by new wells

online

in the Lower 48, Norway, Canada and China.



















46
Segment Results
Alaska
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
(141)
462
(60)
846
Average Net Production
Crude oil (MBD)
153
199
175
205
Natural gas liquids (MBD)
13
17
16
17
Natural gas (MMCFD)
8
7
8
7
Total Production
(MBOED)
167
217
192
223
Average Sales Prices
Crude oil ($ per bbl)
$
26.81
67.57
42.52
65.11
Natural gas ($ per MCF)
2.56
3.19
2.82
3.31

The Alaska segment primarily explores for, produces, transports

and markets crude oil, NGLs and natural gas.

As of June 30, 2020, Alaska contributed 26 percent

of our worldwide liquids production and less than



1

percent of our worldwide natural gas production.

Earnings from Alaska decreased $603 million

and $906 million in the three-



and six-month periods of 2020,
respectively, primarily driven by lower realized crude oil prices,

lower crude oil sales volumes due to
production curtailments at our operated assets on

the North Slope-the Greater Kuparuk Area



(GKA) and
Western North Slope (WNS)-and the absence of $81 million of tax benefits related

to the settlement of
certain tax disputes and enhanced

oil recovery credits.

Average production decreased 50 MBOED and 31 MBOED in the three- and six-month



periods of 2020,
primarily due to curtailments at our operated assets

on the North Slope-GKA and WNS-and normal

field

decline, partly offset by new wells online at WNS.




Curtailment Update
The second quarter 2020 production impact from

curtailments in Alaska was estimated to be

40 MBOED.

Based on our economic criteria, we restored curtailed

production in Alaska during July.





















47
Lower 48
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips

($MM)
$
(365)
206
(802)
399
Average Net Production
Crude oil (MBD)
166
269
218
257
Natural gas liquids (MBD)
64
82
77
78
Natural gas (MMCFD)
486
593
582
581
Total Production
(MBOED)
311
450
392
432
Average Sales Prices
Crude oil ($ per bbl)
$
19.87
59.17
32.92
56.31
Natural gas liquids ($ per bbl)
6.95
17.91
9.81
19.20
Natural gas ($ per MCF)
1.18
2.10
1.36
2.41

The Lower 48 segment consists of operations located



in the U.S. Lower 48 states, as well as producing
properties in the Gulf of Mexico.

As of June 30, 2020, the Lower 48 contributed



41 percent of our worldwide
liquids production and 24 percent of our worldwide

natural gas production.

Earnings from the Lower 48 decreased $571 million

and $1,201 million in the three-



and six-month periods of
2020, respectively, primarily due to lower realized crude oil, NGL and natural

gas prices and lower sales
volumes due to production curtailments.

The earnings decrease in the three- and six-month



periods of 2020
were partly offset by lower DD&A expense, lower production

and operating expenses, and increased equity in
earnings of affiliates.

DD&A expense in the second quarter of 2020 decreased



due to lower production
volumes, primarily associated with curtailments,

partly offset by higher DD&A rates driven by price-related downward reserve revisions.

In addition to the items detailed above, in the six-month



period of 2020, earnings
decreased due to a $399 million after-tax impairment

related to certain non-core gas assets in the



Wind River
Basin operations area, partly offset by the absence of $120

million of impairments in equity method
investments.

See Note 8-Impairments and Note 14-Fair

Value



Measurement in the Notes to Consolidated
Financial Statements, for additional information

related to the Wind River Basin operations area impairment.

Total average production decreased 139 MBOED and 40 MBOED in the three-



and six-month periods of 2020,
respectively, primarily due to normal field decline, production curtailments

and higher unplanned downtime.

Partly offsetting the production decrease, was new production



from unconventional assets in the Eagle Ford,
Permian and Bakken.


Curtailment Update
The second quarter 2020 production impact from

curtailments in the Lower 48 was estimated



to be 145
MBOED.

Based on our economic criteria, we brought some

curtailed volumes in the Lower 48 back online

in

July and expect to be fully restored by September.






















48
Canada
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019**
2020
2019**
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
(86)
100
(195)
222
Average Net Production
Crude oil (MBD)
5
1
4
1
Natural gas liquids (MBD)
2
1
1
-
Bitumen (MBD)
34
51
50
57
Natural gas (MMCFD)
40
8
30
8
Total Production
(MBOED)
48
54
60
59
Average Sales Prices*
Crude oil ($ per bbl)
8.69
-
15.39
-
Natural gas liquids ($ per bbl)
1.64
-
1.89
-
Natural gas ($ per MCF)
0.79
-
1.05
-
Bitumen ($ per bbl)
(23.11)
37.20
(3.09)
35.00
*Average sales prices in the second quarter of 2020 include unutilized
transportation costs.
**Average prices for sales of bitumen excludes additional value realized from
the purchase and sale of third-party volumes for optimization of
our pipeline capacity between Canada and the U.S. Gulf Coast.


Our Canadian operations mainly consist of an oil

sands development in the Athabasca Region of

northeastern

Alberta and a liquids-rich unconventional play

in western Canada.



As of June 30, 2020, Canada contributed 8
percent of our worldwide liquids production and

less than 1 percent of our worldwide natural

gas production.

Earnings from Canada decreased $186 million

and $417 million in the three-



and six-month periods of 2020,
primarily because of lower bitumen price realizations,

production curtailments at Surmont,



the absence of a
$41 million gain on dispositions related to a contingent

payment, and the absence of a $25 million tax

benefit

due to a four year phased four percent reduction in Alberta's corporate income

tax rate.



Partly offsetting this
decrease in earnings was a $48 million refund from

the Alberta Tax & Revenue Administration in the second quarter of 2020.

In addition to the items detailed above, in the



six-month period of 2020, earnings decreased
due to the absence of a $68 million tax

benefit related to a tax settlement.

Total average production decreased 6 MBOED in the second quarter of 2020, primarily



due to production
curtailments at Surmont, partly offset by the absence of a planned

turnaround at Surmont and new production
from Pad 1 at Montney.

Total average production increased 1 MBOED in the six-month period of 2020, primarily due to first production from Pad 1 at

Montney commencing February 2020 and the



absence of a
planned turnaround at Surmont, partly offset by curtailments

at Surmont.




Curtailment Update
The second quarter 2020 production impact from

curtailments in Canada was estimated to be 30

MBOED net.

Based on our economic criteria, we began to restore

some curtailed production at Surmont

in July.




Planned Acquisition
In July 2020, we signed a definitive agreement

to acquire additional Montney acreage for cash consideration

of

approximately $375 million before customary adjustments,



plus the assumption of approximately $30 million
in financing obligations for associated partially

owned infrastructure.



This acquisition primarily consists of
undeveloped properties and includes 140,000

net acres in the liquids-rich Inga Fireweed asset

Montney zone,
which is directly adjacent to our existing Montney

position,

as well as 15 MBOED of production.

Upon

completion of this transaction, we will have a Montney

acreage position of 295,000 net acres with a 100



















49

percent working interest.

The transaction is subject to regulatory



approval and is expected to close in the third
quarter of 2020 with an effective date of July 1, 2020.


Europe and North Africa
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Net Income Attributable to ConocoPhillips
($MM)
$
11
407
86
614
Average Net Production
Crude oil (MBD)
75
130
84
141
Natural gas liquids (MBD)
5
6
5
8
Natural gas (MMCFD)
264
518
287
560
Total Production
(MBOED)
124
223
137
242
Average Sales Prices
Crude oil ($ per bbl)
$
32.32
69.65
44.70
66.16
Natural gas liquids ($ per bbl)
16.76
32.00
18.75
31.49
Natural gas ($ per MCF)
2.21
4.42
3.03
5.58

The Europe and North Africa segment consists

of operations principally located in the Norwegian



sector of the
North Sea and the Norwegian Sea, Libya and commercial

operations in the U.K.



As of June 30, 2020, our
Europe and North Africa operations contributed

12 percent of our worldwide liquids production



and 12 percent
of our worldwide natural gas production.

Earnings for Europe and North Africa decreased by

$396 million and $528 million in the three- and six-month periods of 2020, respectively, primarily due to our U.K. divestiture in the third



quarter of 2019, the absence of
a U.S. tax benefit of $234 million associated

with the recognition of U.S. tax basis in our



disposed U.K.
subsidiaries, and lower crude oil and natural gas realizations.


Average production decreased 99 MBOED and 105 MBOED in the three-

and six-month periods of 2020, respectively, primarily due to our U.K. disposition in the third quarter of 2019,



lower production in Libya due
to a cessation of production following a period

of civil unrest, and normal field decline.



Partly offsetting these
decreases in production were the absence of planned

turnarounds at the Greater Ekofisk



Area and new wells
online in Norway.


Force Majeure in Libya
Production ceased February 12, 2020 due to a forced

shutdown of the Es Sider export terminal



and other
eastern export terminals after a period of civil unrest.

It is unknown when exports will resume.



































50
Asia Pacific and Middle East
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Net Income Attributable to ConocoPhillips

($MM)
$
662
517
1,060
1,042
Average Net Production
Crude oil (MBD)
Consolidated operations
61
89
70
91
Equity affiliates
14
14
13
13
Total crude oil
75
103
83
104
Natural gas liquids (MBD)
Consolidated operations
1
4
2
4
Equity affiliates
8
8
7
7
Total natural gas liquids
9
12
9
11
Natural gas (MMCFD)
Consolidated operations
423
578
522
622
Equity affiliates
1,056
1,064
1,046
1,026
Total natural gas
1,479
1,642
1,568
1,648
Total Production
(MBOED)
331
388
354
390
Average Sales Prices
Crude oil ($ per bbl)
Consolidated operations
$
27.98
69.78
43.02
65.93
Equity affiliates
25.32
63.98
38.52
61.94
Total crude oil
27.45
68.91
42.26
65.43
Natural gas liquids ($ per bbl)
Consolidated operations
27.90
39.97
33.21
40.05
Equity affiliates
23.93
41.72
32.38
40.09
Total natural gas liquids
24.90
41.05
32.59
40.07
Natural gas ($ per MCF)
Consolidated operations
4.74
5.89
5.45
6.14
Equity affiliates
3.90
5.81
4.65
6.53
Total natural gas
4.14
5.84
4.92
6.38

The Asia Pacific and Middle East segment has

operations in China, Indonesia, Malaysia,

Australia and Qatar.

As of June 30, 2020, Asia Pacific and Middle East

contributed 13 percent of our worldwide liquids production and 63 percent of our worldwide natural gas

production.

Earnings increased $145 million and $18 million

in the three-

and six-month periods of 2020, primarily due to



a

$597 million after-tax gain on disposition related

to our Australia-West divestiture and the cessation of DD&A expense associated with our previously held-for-sale Australia-West assets.



Partly offsetting the increase in
earnings, were lower oil, LNG and natural gas prices,

lower LNG sales volumes associated with our disposed Australia-West assets, and lower oil sales volumes,

primarily related to curtailments in Malaysia.












51

Average production decreased 57 MBOED and 36 MBOED in the three-

and six-month periods of 2020, primarily due to the divestiture of our Australia-West assets, normal field decline, the expiration



of the Panyu
production license in China, higher unplanned downtime

due to the rupture of a third-party pipeline impacting gas production from the Kebabangan field in

Malaysia, and curtailments in Malaysia.



Partly offsetting these
production decreases, were new production from development

activity at Bohai Bay in China and production
increases from Malaysia, including first oil

from Gumusut Phase 2 in the third quarter of

2019.




Asset Disposition Update
In the second quarter of 2020, we completed the divestiture

of our Australia-West assets and operations, and
based on an effective date of January 1, 2019, we received

proceeds of $765 million in May with an additional $200 million due upon final investment decision

of the proposed Barossa development project.



Production from
the disposed assets averaged 35 MBOED for the six-month

period of 2020, and proved reserves were
approximately 17 MMBOE at year-end 2019.

For additional information related to this



transaction, see Note 4-
Asset Acquisitions and Dispositions.



Other International
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
(6)
81
22
212

The Other International segment consists of exploration

activities in Colombia, Chile and Argentina.

Earnings from our Other International operations

decreased $87 million and $190 million in



the three- and six-
month periods of 2020, respectively.

The decrease in earnings was primarily



due to the absence of recognizing
$84 million and $231 million in other income related

to a settlement award with PDVSA associated



with prior
operations in Venezuela,

in the three- and six-month periods of 2019, respectively.



See Note 12-
Contingencies and Commitments in the Notes to Consolidated

Financial Statements, for additional
information.












52
Corporate and Other
Millions of Dollars
Three Months Ended
Six Months Ended
June 30
June 30
2020
2019
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
Net interest expense
$
(174)
(131)
(329)
(327)
Corporate general and administrative expenses
(90)
(49)
(40)
(114)
Technology
(9)
(10)
(8)
86
Other income (expense)
458
(3)
(1,213)
433
$
185
(193)
(1,590)
78

Net interest expense consists of interest and financing

expense, net of interest income and capitalized

interest.

Net interest expense increased by $43 million

in the second quarter of 2020, primarily due to



higher interest
from an absence of the settlement of certain

tax disputes and lower interest income from lower



cash and cash
equivalent balances.

Corporate G&A expenses include compensation

programs and staff costs.



These expenses increased by $41
million and decreased by $74 million in the three-

and six-month periods of 2020, respectively, primarily due to mark to market adjustments associated with certain

compensation programs.

Technology includes our investment in new technologies or businesses, as well as licensing

revenues.

Activities are focused on both conventional and tight

oil reservoirs, shale gas, heavy oil, oil



sands, enhanced
oil recovery, as well as LNG.

Earnings from Technology decreased $94 million in the six-month period of 2020 primarily due to lower licensing revenues.

Other income (expense) or "Other" includes certain

corporate tax-related items, foreign currency

transaction

gains and losses, environmental costs associated

with sites no longer in operation, other costs not directly associated with an operating segment, premiums

incurred on the early retirement of debt, unrealized

holding

gains or losses on equity securities, and pension settlement

expense.



"Other" increased by $461 million in the
second quarter of 2020,

primarily due to $521 million higher after-tax



unrealized gain on our Cenovus Energy
common shares,

partly offset by the release of a $92 million deferred tax



asset related to our Australia-West
divestiture.

In the six-month period of 2020, "Other" decreased



by $1,646 million primarily due to a $1,140
million after-tax unrealized loss on our Cenovus

Energy common shares reflected in other income as compared to a $373 million after-tax unrealized gain in the



six-month period of 2019.










53
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
June 30
December 31
2020
2019
Short-term debt
$
146
105
Total debt
14,998
14,895
Total equity
31,493
35,050
Percent of total debt to capital*
32
%
30
Percent of floating-rate debt to total debt
5
%
5
*Capital includes total debt and total equity.


To meet our short-

and long-term liquidity requirements, we look



to a variety of funding sources, including
cash generated from operating activities,

our commercial paper and credit facility programs,



and our ability to
sell securities using our shelf registration

statement.

During the first six months of 2020, the primary uses of our available cash were $2,525 million to support

our ongoing capital expenditures and investments

program,

$1,030 million net purchases of investments,

$726 million to repurchase common stock,



and $913 million to
pay dividends.

During the first six months of 2020, our cash and cash



equivalents decreased by $2,181 million
to $2,907 million.


We entered the year with a strong balance sheet including cash and cash equivalents



of over $5 billion, short-
term investments of $3 billion, and an undrawn

credit facility of $6 billion, totaling



approximately $14 billion
of liquidity.

This strong foundation allowed us to be measured



in our response to the sudden change in
business environment we experienced in the first

quarter of 2020.



In response to the recent oil market
downturn, we announced the following capital,

operating cost and share repurchase reductions.



We reduced
our 2020 operating plan capital expenditures by a

total of $2.3 billion, or approximately thirty-five



percent of
the original guidance.

We suspended our share repurchase program for the remainder of 2020, further reducing cash outlays by approximately $2.3 billion

in 2020.



We are also reducing our operating costs by
approximately $0.6 billion, or roughly ten percent

of the original 2020 guidance.



Collectively, these actions
represent a reduction in 2020 cash uses of over $5

billion versus the original operating plan.

We also established a framework for evaluating and implementing economic curtailments



considering the
weakness in oil prices during the second quarter of

2020, which resulted in taking an additional



significant step
of curtailing production, predominantly from operated

North American assets.



Due to our strong balance
sheet, we were in an advantaged position to forgo some production

and cash flow in anticipation of receiving
higher cash flows for those volumes in the future.

We ended the second quarter with cash and cash equivalents of $2.9 billion, short-term



investments of $4.0
billion, and an undrawn credit facility of $6 billion,

totaling $12.9 billion of liquidity.



We believe current cash
balances and cash generated by operations, the recent

adjustments to our operating plan, together with

access

to external sources of funds as described below in

the "Significant Sources of Capital"



section, will be
sufficient to meet our funding requirements in the near-

and long-term, including our capital spending
program, dividend payments and required debt payments.


Significant Sources of Capital

Operating Activities

Cash provided by operating activities was $2,262

million for the first six months of 2020, compared

with

$5,785 million for the corresponding period of 2019.

The decrease in cash provided by operating activities

is

primarily due to lower realized commodity prices,

production curtailments and the divestiture



of our U.K. and
Australia-West assets.






54
Our short-

and long-term operating cash flows are highly

dependent upon prices for crude oil, bitumen, natural gas, LNG and NGLs.

Prices and margins in our industry have historically



been volatile and are driven by
market conditions over which we have no control.

Absent other mitigating factors, as these prices



and margins
fluctuate, we would expect a corresponding change

in our operating cash flows.

The level of absolute production volumes, as well

as product and location mix, impacts our cash flows.

Production levels are impacted by such factors as

the volatile crude oil and natural gas



price environment,
which may impact investment decisions; the

effects of price changes on production sharing and variable- royalty contracts; acquisition and disposition of fields;



field production decline rates; new technologies;
operating efficiencies; timing of startups and major turnarounds;

political instability; global pandemics and
associated demand decreases; weather-related disruptions;

and the addition of proved reserves through
exploratory success and their timely and cost-effective

development.



While we actively manage these factors,
production levels can cause variability in cash

flows, although generally this variability has not



been as
significant as that caused by commodity prices.


To maintain or grow our production volumes, we must continue to add to our

proved reserve base.



Due to
recent capital reductions, our reserve replacement

efforts could be delayed thus limiting our ability



to replace
depleted reserves.


Investing Activities
Proceeds from asset sales in the first six months

of 2020 were $1.3 billion



compared with $0.7 billion in the
corresponding period of 2019.

In the second quarter of 2020, we completed



the divestiture of our Australia-
West assets and operations.

Based on an effective date of January 1, 2019 and customary



closing adjustments,
we received cash proceeds of $765 million in

the second quarter with another $200 million



payment due upon
final investment decision of the proposed Barossa

development project.



In the first quarter of 2020, proceeds
from asset sales were $549 million, which included

the sale of our Niobrara interests and Waddell Ranch interests in the Lower 48 for proceeds of $359 million

and $184 million, respectively.



See Note 4-Asset
Acquisitions and Dispositions in the Notes to Consolidated

Financial Statements, for additional information

on

these transactions.

Proceeds from asset sales in the first six months

of 2019 were $701 million,



which consisted primarily of $350
million from the sale of our 30 percent interest in

the Greater Sunrise Fields and deposits



of $268 million
related to an April 2019 agreement to sell

two ConocoPhillips U.K. subsidiaries.




Commercial Paper and Credit Facilities
We have a revolving credit facility totaling $6.0 billion, expiring in May 2023.

Our revolving credit facility
may be used for direct bank borrowings, the issuance

of letters of credit totaling up to $500 million, or

as

support for our commercial paper program.

The revolving credit facility is broadly syndicated



among financial
institutions and does not contain any material

adverse change provisions or any covenants

requiring

maintenance of specified financial ratios or credit

ratings.



The facility agreement contains a cross-default
provision relating to the failure to pay principal or interest

on other debt obligations of $200 million or more
by ConocoPhillips, or any of its consolidated subsidiaries.

The amount of the facility is not subject to
redetermination prior to its expiration date.


Credit facility borrowings may bear interest at a margin above



rates offered by certain designated banks in the
London interbank market or at a margin above the overnight

federal funds rate or prime rates offered by
certain designated banks in the United States.

The agreement calls for commitment fees



on available, but
unused, amounts.

The agreement also contains early termination



rights if our current directors or their
approved successors cease to be a majority of the

Board of Directors.

The revolving credit facility supports the ConocoPhillips



Company $6.0 billion commercial paper program,
which is primarily a funding source for short-term

working capital needs.



Commercial paper maturities are
generally limited to 90 days.




55

We had no commercial paper outstanding at June 30, 2020 or December 31, 2019.



We had no direct
outstanding borrowings or letters of credit

under the revolving credit facility at June 30, 2020 or

December 31,
2019.

Since we had no commercial paper outstanding

and had issued no letters of credit, we had



access to
$6.0 billion in borrowing capacity under our revolving

credit facility at June 30, 2020.



We may consider
issuing commercial paper in the future to supplement

our cash position as appropriate.

Despite recent volatility and price weakness for energy issuers



in the debt capital markets, we believe the
company continues to have access to the markets

based on the composition of our balance sheet



and asset
portfolio.

In March 2020, S&P affirmed its "A" rating on our senior

long-term debt and revised its outlook to "negative" from "stable."

In April 2020, Moody's affirmed their rating of "A3" with a "stable" outlook.



Our current
rating from Fitch is "A" with a "stable" outlook.

We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby



impact our access to liquidity, in the event of a
downgrade of our credit rating.

If our credit rating were downgraded, it could



increase the cost of corporate
debt available to us and potentially restrict

our access to the commercial paper and debt capital

markets.



If our
credit rating were to deteriorate to a level prohibiting

us from accessing the commercial paper and



debt capital
markets, we would still be able to access funds

under our revolving credit facility.

Certain of our project-related contracts, commercial

contracts and derivative instruments contain

provisions

requiring us to post collateral.

Many of these contracts and instruments permit



us to post either cash or letters
of credit as collateral.

At June 30, 2020 and December 31, 2019, we had



direct bank letters of credit of $196
million and $277 million, respectively, which secured performance obligations

related to various purchase
commitments incident to the ordinary conduct of

business.



In the event of credit ratings downgrades, we may
be required to post additional letters of

credit.

Shelf Registration We have a universal shelf registration statement on file with the U.S. SEC under which



we have the ability to
issue and sell an indeterminate amount of various

types of debt and equity securities.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations

and consistent with normal industry practice,



we enter into
numerous agreements with other parties to pursue

business opportunities, which share costs



and apportion
risks among the parties as governed by the agreements.

For information about guarantees, see Note 11-Guarantees, in



the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.

Capital Requirements

For information about our capital expenditures

and investments, see the "Capital Expenditures"

section.

Our debt balance at June 30, 2020, was $14,998

million, compared with $14,895 million



at December 31,
2019.

Maturities of debt for the remainder of 2020,

and for each of the years 2021 through 2024,



are: $81
million, $255 million, $971 million, $229 million

and $573 million, respectively.

On February 4, 2020, we announced a quarterly

dividend of $0.42 per share.



The dividend was paid on March
2, 2020,

to stockholders of record at the close of business

on February 14, 2020.



On April 30, 2020, we
announced a quarterly dividend of $0.42 per share.

The dividend was paid on June 1, 2020, to stockholders

of

record at the close of business on May 11, 2020.

On July 8, 2020,



we announced a quarterly dividend of $0.42
per share, payable September 1, 2020,

to stockholders of record at the close of business



on July 20,

2020.

In late 2016, we initiated our current share repurchase

program.



As of June 30, 2020, we had announced a
total authorization to repurchase $25 billion of our

common stock.

As of December 31, 2019, we had













56

repurchased $9.6 billion of shares.

In the first quarter of 2020, we repurchased



an additional $726 million of
shares.

On April 16, 2020, as a response to the oil market



price downturn, we announced we were suspending
our share repurchase program.

Since our share repurchase program began in November



2016, we have
repurchased 184 million shares at a cost of $10.4

billion through June 30, 2020.




Capital Expenditures
Millions of Dollars
Six Months Ended
June 30
2020
2019
Alaska
$
732
780
Lower 48
1,130
1,770
Canada
142
232
Europe and North Africa
251
339
Asia Pacific and Middle East
188
219
Other International
63
1
Corporate and Other
19
25
Capital expenditures and investments
$
2,525
3,366

During the first six months of 2020, capital expenditures



and investments supported key exploration and
development programs, primarily:

?

Development,

appraisal and exploration activities in



the Lower 48, including Eagle Ford, Permian
Unconventional and Bakken.
?

Appraisal,

exploration and development activities



in Alaska related to the Western North Slope;
development activities in the Greater Kuparuk

Area and the Greater Prudhoe Area.



?

Development and exploration activities across



assets in Norway.
?

Appraisal activities in the liquids-rich portion

of the Montney in Canada and optimization



of oil sands
development.
?

Continued development in China, Malaysia,

Australia and Indonesia.



?

Lease acquisition and exploration activities

in Argentina.

In February 2020, we announced 2020 operating

plan capital expenditures of $6.5 billion to $6.7 billion.

In

response to the recent oil market downturn, we announced

reductions to this plan totaling $2.3 billion,

or

approximately 35 percent.

The capital reductions are sourced to the segments



in the amount of $1.4 billion to
Lower 48, $0.4 billion to Alaska, $0.2 billion

to Canada and $0.3 billion to all other segments

and exploration.

This does not include capital for acquisitions.

In July 2020, we signed a definitive agreement

to acquire additional Montney acreage for cash



consideration of
approximately $375 million before customary adjustments,

plus the assumption of approximately $30 million
in financing obligations for associated partially

owned infrastructure.



This acquisition primarily consists of
undeveloped properties and includes 140,000

net acres in the liquids-rich Inga Fireweed asset

Montney zone,
which is directly adjacent to our existing Montney

position, as well as 15 MBOED of production.

Upon

completion of this transaction, we will have a Montney



acreage position of 295,000 net acres with a 100
percent working interest.

The transaction is subject to regulatory



approval and is expected to close in the third
quarter of 2020 with an effective date of July 1, 2020.




57
Contingencies

A number of lawsuits involving a variety of claims

arising in the ordinary course of business



have been filed
against ConocoPhillips.

We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain

chemical, mineral and petroleum substances



at various active
and inactive sites.

We regularly assess the need for accounting recognition or disclosure of these contingencies.

In the case of all known contingencies (other

than those related to income taxes), we accrue



a

liability when the loss is probable and the amount

is reasonably estimable.



If a range of amounts can be
reasonably estimated and no amount within the range

is a better estimate than any other amount,



then the
minimum of the range is accrued.

We do not reduce these liabilities for potential insurance or third-party recoveries.

We accrue receivables for insurance or other third-party recoveries when applicable.



With respect
to income-tax-related contingencies, we use a

cumulative probability-weighted loss accrual



in cases where
sustaining a tax position is less than certain.

Based on currently available information, we believe

it is remote that future costs related to known

contingent

liability exposures will exceed current accruals by

an amount that would have a material



adverse impact on our
consolidated financial statements.

As we learn new facts concerning contingencies,



we reassess our position
both with respect to accrued liabilities

and other potential exposures.



Estimates particularly sensitive to future
changes include contingent liabilities

recorded for environmental remediation, legal and

tax matters.

Estimated future environmental remediation

costs are subject to change due to such factors as



the uncertain
magnitude of cleanup costs, the unknown time

and extent of such remedial actions that



may be required, and
the determination of our liability in proportion

to that of other responsible parties.



Estimated future costs
related to legal and tax matters are subject to

change as events evolve and as additional



information becomes
available during the administrative and litigation

processes.



For information on other contingencies, see
Note 12-Contingencies

and Commitments, in the Notes to Consolidated

Financial Statements.

Legal and Tax Matters We are subject to various lawsuits and claims including but not limited to matters



involving oil and gas royalty
and severance tax payments, gas measurement and

valuation methods, contract disputes,

environmental

damages, climate change, personal injury, and property damage.



Our primary exposures for such matters
relate to alleged royalty and tax underpayments

on certain federal, state and privately owned



properties and
claims of alleged environmental contamination

from historic operations.



We will continue to defend ourselves
vigorously in these matters.

Our legal organization applies its knowledge, experience



and professional judgment to the specific
characteristics of our cases, employing a litigation

management process to manage and monitor the

legal

proceedings against us.

Our process facilitates the early evaluation and quantification



of potential exposures in
individual cases.

This process also enables us to track those cases that



have been scheduled for trial and/or
mediation.

Based on professional judgment and experience



in using these litigation management tools and
available information about current developments

in all our cases, our legal organization regularly assesses

the

adequacy of current accruals and determines if

adjustment of existing accruals, or establishment



of new
accruals, is required.

Environmental

We are subject to the same numerous international, federal, state and local environmental



laws and regulations
as other companies in our industry.

For a discussion of the most significant



of these environmental laws and
regulations, including those with associated remediation

obligations, see the "Environmental" section in
Management's Discussion and Analysis of Financial Condition and Results

of Operations on pages 60-62 of
our 2019 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability



from the EPA and state
environmental agencies alleging that we are

a potentially responsible party under the Federal

Comprehensive

Environmental Response, Compensation and Liability

Act (CERCLA) or an equivalent state statute.

On

occasion, we also have been made a party to cost

recovery litigation by those agencies or by private

parties.

These requests, notices and lawsuits assert potential

liability for remediation costs at various sites

that typically

58

are not owned by us, but allegedly contain waste attributable

to our past operations.



As of June 30, 2020, there
were 15 sites around the U.S.

in which we were identified as a potentially responsible



party under CERCLA
and comparable state laws.

At June 30, 2020 and December 31, 2019, our balance

sheet included a total environmental accrual of

$171

million for remediation activities in the

U.S. and Canada.



We expect to incur a substantial amount of these
expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with



other companies engaged in similar businesses,
environmental costs and liabilities are inherent

concerns in our operations and products, and there



can be no
assurance that material costs and liabilities

will not be incurred.



However, we currently do not expect any
material adverse effect upon our results of operations or financial

position as a result of compliance with
current environmental laws and regulations.

Climate Change
Continuing political and social attention to the

issue of global climate change has resulted in



a broad range of
proposed or promulgated state, national and international

laws focusing on GHG reduction.



These proposed or
promulgated laws apply or could apply in countries

where we have interests or may have interests

in the future.

Laws in this field continue to evolve, and while

it is not possible to accurately estimate either



a timetable for
implementation or our future compliance costs

relating to implementation, such laws, if



enacted, could have a
material impact on our results of operations and

financial condition.



Examples of legislation and precursors
for possible regulation that do or could affect our operations

include:

?

The EPA's

and U.S. Department of Transportation's joint promulgation of a Final Rule on April

1,

2010, that triggered regulation of GHGs under the



Clean Air Act, may trigger more climate-based
claims for damages, and may result in longer

agency review time for development projects.
?

Colorado's HB-19 1261, approved May 30, 2019, introducing statewide goals



to reduce 2025 GHG
emissions by at least 26 percent, 2030 GHG emissions

by at least 50 percent, and 2050 GHG
emissions by at least 90 percent of the levels of GHG

emissions that existed in 2005.

For other examples of legislation or precursors for

possible regulation and factors on which



the ultimate impact
on our financial performance will depend, see the

"Climate Change" section in Management's Discussion and Analysis of Financial Condition and Results of Operations



on pages 63-65 of our 2019 Annual Report on
Form 10-K.

In December 2018, we became a Founding Member

of the Climate Leadership Council (CLC), an

international

policy institute founded in collaboration with business



and environmental interests to develop a carbon
dividend plan.

Participation in the CLC provides another



opportunity for ongoing dialogue about carbon
pricing and framing the issues in alignment with our

public policy principles.



We also belong to and fund
Americans For Carbon Dividends, the education

and advocacy branch of the CLC.

Beginning in 2017, cities, counties, and state governments

in California, New York, Washington,

Rhode

Island, Maryland and Hawaii, as well as the Pacific

Coast Federation of Fishermen's Association, Inc., have filed lawsuits against oil and gas companies,

including ConocoPhillips, seeking compensatory



damages and
equitable relief to abate alleged climate change impacts.

ConocoPhillips is vigorously defending against

these

lawsuits.

The lawsuits brought by the Cities of San Francisco,

Oakland and New York were dismissed by
federal district courts.

The New York dismissal remains on appeal.



The Ninth Circuit ruled that the San
Francisco and Oakland cases (and other California

cases) should proceed in state court, with that

decision

subject to appeal.

Lawsuits filed by the cities and counties in California,

Washington, and Hawaii are
currently stayed pending resolution of the Ninth Circuit

appeals.



Lawsuits filed in Maryland and Rhode Island
are proceeding in state court while rulings in those

matters, on the issue of whether the



matters should proceed
in state or federal court, are on appeal.

Several Louisiana parishes have filed lawsuits against



oil and gas companies, including ConocoPhillips,
seeking compensatory damages in connection

with historical oil and gas operations in Louisiana.

The lawsuits

59

are stayed pending an appeal with the Fifth Circuit

on the issue of whether they will proceed in federal



or state
court.

ConocoPhillips will vigorously defend against



these lawsuits.


CAUTIONARY STATEMENT

FOR THE PURPOSES OF THE "SAFE HARBOR"



PROVISIONS OF
THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements

within the meaning of Section 27A of the Securities



Act of
1933 and Section 21E of the Securities Exchange

Act of 1934.



All statements other than statements of
historical fact included or incorporated by reference

in this report, including, without limitation,

statements

regarding our future financial position, business

strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations,

are forward-looking statements.



Examples of
forward-looking statements contained in this report

include our expected production growth and

outlook on the business environment generally, our expected capital budget and capital expenditures,



and discussions
concerning future dividends.

You can often identify our forward-looking statements by the words "anticipate," "estimate," "believe," "budget," "continue," "could,"

"intend," "may," "plan," "potential," "predict," "seek," "should," "will," "would," "expect," "objective,"

"projection," "forecast," "goal," "guidance," "outlook," "effort," "target" and similar expressions.

We based the forward-looking statements on our current expectations, estimates



and projections about
ourselves and the industries in which we operate in

general.



We caution you these statements are not
guarantees of future performance as they involve

assumptions that, while made in good faith,



may prove to be
incorrect, and involve risks and uncertainties

we cannot predict.



In addition, we based many of these forward-
looking statements on assumptions about future events

that may prove to be inaccurate.



Accordingly, our
actual outcomes and results may differ materially from

what we have expressed or forecast in the forward- looking statements.

Any differences could result from a variety of factors,



including, but not limited to, the
following:


?

The impact of public health crises, including pandemics



(such as COVID-19) and epidemics and any
related company or government policies or

actions.


?

Global and regional changes in the demand, supply, prices, differentials or other market

conditions

affecting oil and gas, including changes resulting from a public



health crisis or from the imposition or
lifting of crude oil production quotas or other

actions that might be imposed by OPEC



and other
producing countries and the resulting company

or third-party actions in response to such changes. ?

Fluctuations in crude oil, bitumen, natural gas,

LNG and NGLs prices, including a prolonged

decline

in these prices relative to historical or future



expected levels.
?

The impact of significant declines in prices for crude

oil, bitumen, natural gas, LNG and NGLs,

which

may result in recognition of impairment charges on our



long-lived assets, leaseholds and
nonconsolidated equity investments.
?

Potential failures or delays in achieving expected

reserve or production levels from existing



and future
oil and gas developments, including due to operating

hazards, drilling risks and the inherent
uncertainties in predicting reserves and reservoir

performance.


?

Reductions in reserves replacement rates, whether

as a result of the significant declines in commodity prices or otherwise. ?

Unsuccessful exploratory drilling activities

or the inability to obtain access to exploratory acreage. ?

Unexpected changes in costs or technical requirements



for constructing, modifying or operating E&P
facilities.
?

Legislative and regulatory initiatives

addressing environmental concerns, including initiatives addressing the impact of global climate change or further



regulating hydraulic fracturing, methane
emissions, flaring or water disposal.
?

Lack of, or disruptions in, adequate and reliable

transportation for our crude oil, bitumen, natural



gas,
LNG and NGLs.

60
?

Inability to timely obtain or maintain permits,

including those necessary for construction, drilling and/or development, or inability to make capital

expenditures required to maintain compliance

with

any necessary permits or applicable laws or regulations. ?

Failure to complete definitive agreements and feasibility



studies for, and to complete construction of,
announced and future E&P and LNG development

in a timely manner (if at all) or on budget.
?

Potential disruption or interruption of our operations

due to accidents, extraordinary weather

events,

civil unrest, political events, war, terrorism, cyber attacks,



and information technology failures,
constraints or disruptions.
?

Changes in international monetary conditions and



foreign currency exchange rate fluctuations.
?

Changes in international trade relationships,

including the imposition of trade restrictions



or tariffs
relating to crude oil, bitumen, natural gas, LNG,

NGLs and any materials or products (such as
aluminum and steel) used in the operation of our

business.


?

Substantial investment in and development use

of, competing or alternative energy sources, including as a result of existing or future environmental



rules and regulations.
?

Liability for remedial actions, including removal

and reclamation obligations, under existing

and


future environmental regulations and litigation.
?

Significant operational or investment changes imposed

by existing or future environmental

statutes

and regulations, including international agreements

and national or regional legislation and regulatory measures to limit or reduce GHG emissions. ?

Liability resulting from litigation or our failure

to comply with applicable laws and regulations.



?

General domestic and international economic and

political developments, including armed

hostilities;

expropriation of assets; changes in governmental

policies relating to crude oil, bitumen, natural

gas,

LNG and NGLs pricing, regulation or taxation;



and other political, economic or diplomatic
developments.
?

Volatility

in the commodity futures markets.
?

Changes in tax and other laws, regulations (including



alternative energy mandates), or royalty rules
applicable to our business.
?

Competition and consolidation in the oil and gas



E&P industry.
?

Any limitations on our access to capital or increase

in our cost of capital, including as a result

of

illiquidity or uncertainty in domestic or international



financial markets.
?

Our inability to execute, or delays in the completion,

of any asset dispositions or acquisitions



we elect
to pursue.

?

Potential failure to obtain, or delays in obtaining, any

necessary regulatory approvals for



pending or
future asset dispositions or acquisitions,

or that such approvals may require modification



to the terms
of the transactions or the operation of our remaining

business.


?

Potential disruption of our operations as a result

of pending or future asset dispositions or acquisitions, including the diversion of management time and attention. ?

Our inability to deploy the net proceeds from any

asset dispositions that are pending or



that we elect to
undertake in the future in the manner and timeframe

we currently

anticipate, if at all.
?

Our inability to liquidate the common stock issued



to us by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem

acceptable, or at all.
?

The operation and financing of our joint ventures. ?

The ability of our customers and other contractual

counterparties to satisfy their obligations to

us,

including our ability to collect payments when

due from the government of Venezuela or PDVSA.



?

Our inability to realize anticipated cost savings and



capital expenditure reductions.
?

The inadequacy of storage capacity for our products,

and ensuing curtailments, whether voluntary

or

involuntary, required to mitigate this physical constraint. ?

The risk factors generally described in Part II-Item



1A in this report, in Part I-Item 1A in our 2019
Annual Report on Form 10-K, and any additional

risks described in our other filings with



the SEC.



61
Item 3.

QUANTITATIVE

AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

Information about market risks for the six months

ended June 30, 2020, does not differ materially



from that
discussed under Item 7A in our 2019 Annual Report

on Form 10-K.



Item 4.

CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure information required



to be disclosed in
reports we file or submit under the Securities

Exchange Act of 1934, as amended (the Act),



is recorded,
processed, summarized and reported within the

time periods specified in SEC rules and forms,



and that such
information is accumulated and communicated

to management, including our principal



executive and principal
financial officers, as appropriate, to allow timely decisions

regarding required disclosure.



As of June 30, 2020,
with the participation of our management, our Chairman

and Chief Executive Officer (principal executive officer) and our Executive Vice President and Chief Financial Officer (principal financial



officer) carried out
an evaluation, pursuant to Rule 13a-15(b) of

the Act, of ConocoPhillips' disclosure controls



and procedures (as
defined in Rule 13a-15(e) of the Act).

Based upon that evaluation, our Chairman and

Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded our disclosure



controls and
procedures were operating effectively as of June 30, 2020.

There have been no changes in our internal

control over financial reporting, as defined in



Rule 13a-15(f) of the
Act, in the period covered by this report that

have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.




PART

II.

OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

There are no new material legal proceedings

or material developments with respect to matters

previously

disclosed in Item 3 of our 2019 Annual Report on



Form 10-K.


Item 1A.

RISK FACTORS

Other than the risk factors set forth below, there have been no material



changes to the risk factors disclosed in
our Annual Report on Form 10-K for the fiscal

year ended December 31, 2019.

Our business has been, and will continue to

be, affected by the coronavirus (COVID-19) pandemic.

The COVID-19 outbreak and the measures put

in place to address it have negatively impacted



the global
economy, disrupted global supply chains, reduced global demand for oil

and gas, and created significant
volatility and disruption of financial and commodity

markets.



Public health officials have recommended or
mandated certain precautions to mitigate

the spread of COVID-19, including limiting non-essential

gatherings

of people, ceasing all non-essential travel

and issuing "social or physical distancing" guidelines,

"shelter-in-

place" orders and mandatory closures or reductions

in capacity for non-essential businesses.



The full impact of
the COVID-19 pandemic remains uncertain

and will depend on the severity, location and duration of the effects and spread of the disease, the effectiveness and duration



of actions taken by authorities to contain the
virus or treat its effect, and how quickly and to what extent

economic conditions improve.



According to the
National Bureau of Economic Research, as a result

of the pandemic and its broad reach across the

entire

economy, the U.S. entered a recession in early 2020.

We have already been impacted by the COVID-19 pandemic.



See Management's Discussion and Analysis of
Financial Condition and Results of Operations, for

additional information on how we have



been impacted and
the steps we have taken in response.


62

Our business is likely to be further negatively

impacted by the COVID-19 pandemic. These impacts

could

include but are not limited to:



?

Continued reduced demand for our products



as a result of reductions in travel and commerce;
?

Disruptions in our supply chain due in part to scrutiny



or embargoing of shipments from infected areas
or invocation of force majeure clauses in commercial

contracts due to restrictions imposed as a result
of the global response to the pandemic;
?

Failure of third parties on which we rely, including our suppliers, contract



manufacturers, contractors,
joint venture partners and external business partners,

to meet their obligations to the company, or
significant disruptions in their ability to

do so, which may be caused by their own financial

or

operational difficulties or restrictions imposed in



response to the disease outbreak;
?

Reduced workforce productivity caused by, but not limited to, illness, travel



restrictions, quarantine,
or government mandates;
?

Business interruptions resulting from a significant

amount of our employees telecommuting

in

compliance with social distancing guidelines and



shelter-in-place orders, as well as the
implementation of protections for employees continuing

to commute for work, such as personnel
screenings and self-quarantines before or after

travel; and
?

Voluntary

or involuntary curtailments to support oil prices



or alleviate storage shortages for our
products.

Any of these factors, or other cascading effects of the

COVID-19 pandemic that are not currently foreseeable, could materially increase our costs, negatively impact

our revenues and damage our financial condition,

results

of operations, cash flows and liquidity position.

The pandemic continues to progress and evolve,



and the full
extent and duration of any such impacts cannot

be predicted at this time because of the sweeping



impact of the
COVID-19 pandemic on daily life around the world.

We have been negatively affected and are likely to continue to be negatively affected by the recent



swift and
sharp drop in commodity prices.

The oil and gas business is fundamentally a commodity

business and prices for crude oil, bitumen,



natural gas,
NGLs and LNG can fluctuate widely depending

upon global events or conditions that affect supply and demand.

Recently, there has been a precipitous decrease in demand for oil globally, largely caused by the dramatic decrease in travel and commerce resulting

from the COVID-19 pandemic.



See Management's
Discussion and Analysis of Financial Condition

and Results of Operations, for additional information

on

commodity prices and how we have been impacted.

There is no assurance of when or if commodity



prices will
return to pre-COVID-19 levels.

The speed and extent of any recovery remains uncertain



and is subject to
various risks, including the duration, impact and actions

taken to stem the proliferation of the COVID-19
pandemic, the extent to which those nations party

to the OPEC plus production agreement decide



to increase
production of crude oil, bitumen, natural gas, NGLs

and LNG, and other risks described in this

Quarterly

Report on Form 10-Q or in our Annual Report

on Form 10-K for the fiscal year ended

December 31, 2019.

Even after a recovery, our industry will continue to be exposed to the effects of changing



commodity prices
given the volatility in commodity price drivers

and the worldwide political and economic

environment

generally, as well as continued uncertainty caused by armed hostilities



in various oil-producing regions around
the globe.

Our revenues, operating results and future rate

of growth are highly dependent on the prices

we

receive for our crude oil, bitumen, natural gas, NGLs

and LNG.



Many of the factors influencing these prices
are beyond our control.


Lower crude oil, bitumen, natural gas, NGL and LNG

prices may have a material adverse effect on our revenues, operating income, cash flows and liquidity, and may also affect the amount



of dividends we elect to
declare and pay on our common stock.

As a result of the recent market downturn, we



have suspended our
share repurchase program.

Lower prices may also limit the amount of reserves



we can produce economically,
thus adversely affecting our proved reserves, reserve replacement

ratio and accelerating the reduction in our












63

existing reserve levels as we continue production

from upstream fields.



Prolonged lower crude oil prices may
affect certain decisions related to our operations, including

decisions to reduce capital investments



or decisions
to shut-in production.

Due to ongoing uncertainty and volatility, we are suspending all further



guidance for
2020, including guidance related to capital

expenditures and production and our previous



2020 guidance
should not be relied upon.

Significant reductions in crude oil, bitumen, natural

gas, NGLs and LNG prices could also



require us to reduce
our capital expenditures, impair the carrying value

of our assets or discontinue the classification



of certain
assets as proved reserves.

In the first six-month period of 2020, we recognized



several impairments, which are
described in Note 8-Impairments.

If the outlook for commodity prices remain



low relative to their historic
levels, and as we continue to optimize our investments

and exercise capital flexibility, it is reasonably likely we will incur future impairments to long-lived assets

used in operations, investments in nonconsolidated entities accounted for under the equity method and unproved

properties.



If oil and gas prices persist at
depressed levels, our reserve estimates may

decrease further, which could incrementally increase the rate used to determine DD&A expense on our unit-of-production

method properties.



See Management's Discussion and
Analysis for further examination of DD&A

rate impacts versus comparative periods.



Although it is not
reasonably practicable to quantify the impact

of any future impairments or estimated change to our

unit-of-

production at this time, our results of operations

could be adversely affected as a result.

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
April 1-30, 2020
-
$
-
-
$
14,649
May 1-31, 2020
-
-
-
14,649
June 1-30, 2020
-
-
-
14,649
-
$
-
-

*There were no repurchases of common stock from company employees in connection
with the company's broad-based employee incentive plans.


In late 2016, we initiated our current share repurchase

program.



As of June 30, 2020, we had announced a
total authorization to repurchase $25 billion of our

common stock.



As of December 31, 2019, we had
repurchased $9.6 billion of shares.

In the first quarter of 2020, we repurchased



an additional $726 million of
shares.

On April 16, 2020, as a response to the oil market



downturn, we announced we were suspending our
share repurchase program.

Acquisitions for the share repurchase program



are made at management's
discretion, at prevailing prices, subject to market conditions

and other factors.



Except as limited by applicable
legal requirements, repurchases may be increased, decreased

or discontinued at any time without prior notice.

Shares of stock repurchased under the plan are

held as treasury shares.



See the "Our ability to declare and pay
dividends and repurchase shares is subject to

certain considerations" section in Risk Factors



on pages 21-22 of
our 2019 Annual Report on Form 10-K.

64
Item 6.

EXHIBITS

10.1*

Letter Agreement with Don E. Wallette, Jr., dated August 3, 2020.

31.1*

Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities

Exchange Act of 1934.

31.2*

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities

Exchange Act of 1934.

32*


  Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*
Inline XBRL Instance Document.
101.SCH*
Inline XBRL Schema Document.
101.CAL*
Inline XBRL Calculation Linkbase Document.
101.LAB*
Inline XBRL Labels Linkbase Document.
101.PRE*
Inline XBRL Presentation Linkbase Document.
101.DEF*
Inline XBRL Definition Linkbase Document.
104*
Cover Page Interactive Data File (formatted

as Inline XBRL and contained in Exhibit 101).
* Filed herewith.


65

© Edgar Online, source Glimpses