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Item 7. Management’s Discussion and Analysis

2022-02-17 compared with 2021-02-16 · 3067 added, 2769 removed, 344 unchanged (94% of the section changed)

MANAGEMENT’S DISCUSSION AND

ANALYSIS OF FINANCIAL CONDITION AND

Management’s Discussion and Analysis of Financial Condition and

Results of Operations

Discussion and Analysis is the company’s analysis of its financial performance and of

significant trends that may affect future performance.

It should be read in conjunction with the financial

statements and notes, and supplemental oil

and gas disclosures included elsewhere in this report.

forward-looking statements including, without limitation, statements

relating to the company’s

strategies, objectives, expectations and intentions

that are made pursuant to the “safe harbor” provisions of

the Private Securities Litigation Reform Act of

The words “anticipate,” “believe,” “budget,”

“continue,” “could,” “effort,” “estimate,” “expect,”

“forecast,” “goal,” “guidance,” “intend,” “may,”

“objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,”

“should,” “target,” “will,”

“would,” 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

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

notes, and supplemental oil and gas disclosures included

elsewhere in this report.

It contains forward-looking

statements including, without limitation,

statements relating to the company’s

plans, strategies, objectives,

expectations and intentions

that are made pursuant to the “safe harbor” provisions of the Private Securities

Litigation Reform Act of 1995.

The words “anticipate,”

“believe,” “budget,”

“intend,” “may,”

“plan,” “potential,”

“predict,” “projection,”

“seek,” “should,”

“target,” “will,”

“would,” and similar expressions

identify forward-looking

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

FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS

OF THE PRIVATE

SECURITIES LITIGATION

REFORM ACT OF 1995,”

beginning on page

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)

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

ConocoPhillips is an independent E&P company

with operations and activities in 15 countries.

low cost of supply portfolio includes resource-rich

unconventional plays in North America;

assets in North America, Europe and Asia;

LNG developments;

Business Environment and Executive Overview

ConocoPhillips is one of the world’s

leading E&P companies based on both production and reserves

operations and activities in 14 countries.

Our diverse, low cost of supply portfolio

includes resource-rich

unconventional plays

in North America;

conventional assets in North

America, Europe and Asia;

developments;

oil sands assets in Canada;

and an inventory of

global conventional and unconventional exploration

Headquartered in Houston, Texas, at

December 31, 2020, we employed approximately

9,700 people worldwide and had total

inventory of global conventional

and unconventional exploration

Headquartered in Houston, Texas,

at December 31, 2021, we employed approximately

worldwide and had total

assets of $91 billion.

Completed Acquisition of Concho Resources Inc.

Completed Acquisitions

On January 15, 2021, we completed our acquisition

1 unchanged sentence

(Concho), an independent

and gas exploration and production company

with operations across New Mexico and West Texas.

addition of complementary acreage in the

Delaware and Midland Basins creates a sizeable

Permian presence to

augment our leading unconventional positions

in the Eagle Ford and Bakken in the Lower 48

and the Montney

Consideration for the all-stock transaction was

valued at $13.1 billion, in which 1.46 shares

of ConocoPhillips

common stock was exchanged for each outstanding

share of Concho common stock, resulting

in the issuance

of approximately 286 million shares of ConocoPhillips

common stock.

We also assumed $3.9 billion in

aggregate principal amount of outstanding debt for

Concho, which was recorded at fair value of $4.7

of the closing date.

The combined companies are expected to

capture approximately $750 million of annual

cost and capital savings by 2022.

For additional information

related to this transaction, see Note 25—

Acquisition of Concho Resources Inc.

Notes to Consolidated Financial Statements.

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 the

COVID-19 pandemic,

continues to have unprecedented social and economic

consequences.

Mitigation efforts to stop the spread of

this highly-contagious disease include stay-at-home

orders and business closures that caused

contractions in economic activity worldwide.

The supply shock was triggered by disagreements

OPEC and Russia, beginning in early March 2020,

which resulted in significant supply coming

and an oil price war.

These dual demand and supply shocks caused

oil prices to collapse as we exited

the first quarter of 2020.

As we entered the second quarter of 2020, predictions

of COVID-19 driven global oil demand losses

intensified, with forecasts

of unprecedented demand declines.

Based on these forecasts, OPEC plus nations

held an emergency meeting, and in April they announced

a coordinated production cut that was unprecedented

in both its magnitude and duration.

The OPEC plus agreement spans from May 2020

until April 2022, with

the volume of production cuts easing over time.

Additionally, non-OPEC plus countries, including the U.S.,

Canada, Brazil and other G-20 countries,

announced organic reductions to production through the

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

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

positions and avoid taking

physical delivery.

As storage constraints approached, spot prices in

April for certain North American

landlocked grades of crude oil were in the single digits

or even negative for particularly remote or low-grade

crudes, while waterborne priced crudes such as

Brent sold at a relative advantage.

The extreme volatility

in the first half of the year settled down in the

second half of the year, with WTI crude oil prices

exiting the year near $50 per barrel.

Since the start of the severe downturn, we have closely

monitored the market and taken prudent actions in

response to this situation.

We entered 2020 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 2020.

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

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 decreased uses of cash by approximately

exploration and production

company with operations across

New Mexico and West Texas

in an all-stock

transaction for $13.1 billion.

In December 2021, we completed our acquisition

of Shell Enterprises LLC’s (Shell) assets in the

Delaware Basin in

an all-cash transaction for $8.7 billion after

customary adjustments.

Assets acquired include approximately

225,000 net acres of producing properties

located entirely in Texas.

See Item 1A “Risk Factors” for

further discussion of the risks related to integration of the assets acquired.

After an unprecedented 2020, the energy

landscape improved throughout

2021 with prices reaching pre-pandemic

levels in the second half of the year;

we expect prices will continue to be cyclical

and volatile.

that a successful business strategy

in the E&P industry must be resilient in lower price

environments while also

retaining upside during periods of higher prices.

we are unhedged, remain highly disciplined

investment decisions and continually

monitor market fundamentals,

including OPEC Plus updates regarding

guidance and inventory levels.

Although global oil demand improved through

2021, the global economic recovery

remains uncertain and subject to various

risk factors, including actions taken

to stem the proliferation

Management’s Discussion and Analysis

ConocoPhillips

As the macro energy environment

continues to evolve, we

are embracing what we believe

sector leadership

requires through what we call

our triple mandate.

We believe that ConocoPhillips

will play an essential role in

meeting energy transition pathway

demand delivering superior and consistent

returns on and of capital through

the price cycles,

and achieving our net zero ambition

on operational emissions,

while retaining the flexibility to

successfully adapt as the future unfolds.

Our triple mandate is supported by financial principles

and capital allocation priorities that

should allow us to

deliver superior returns through the cycles.

Our financial principles consist of maintaining

balance sheet strength,

providing peer-leading distributions,

making disciplined investments, and delivering

ESG excellence, all of which

are in service to delivering competitive financial returns.

Our 2021 acquisitions of Concho and the Shell Permian

assets further reinforce our differential

value proposition.

In 2021, we successfully delivered on our priorities.

company production was

1,567 MBOED yielding cash

provided by operating activities

of $17 billion.

$5.3 billion into the business in the form of capital

expenditures and provided returns

of capital to shareholders of approximately

$6 billion through our ordinary

dividend and share repurchases.

For 2021, our ordinary dividend returned $2.4 billion

which included an increase

from 43 cents per share to 46 cents

effective in December.

Share repurchases resumed

in February and

amounted to $3.6 billion inclusive of our paced

monetization program related

to the Cenovus Energy (CVE)

common shares owned.

We also demonstrated

our commitment to preserving our top-tier balance

sheet with an announcement to reduce the company’s

gross debt by $5 billion over five years

combination of natural and accelerated

As part of our ongoing portfolio high-grading

and optimization efforts,

in December 2021, we announced two

transactions in our Asia Pacific segment enhancing

our diverse portfolio.

This included notifying Origin Energy of

our intent to exercise

our preemption right to purchase

an additional 10 percent shareholding interest

for $1.645 billion, before customary

and the sale of our interests in Indonesia for

approximately $1.4

billion before customary adjustments.

In addition to those transactions, in January 2022, we entered

divestiture agreement to sell our

interest in noncore assets within

our Lower 48 segment for $440 million.

transactions are expected to

close in the first half of 2022.

For more information on APLNG,

more information on pending dispositions,

We announced an increase in our

disposition target to $4 to $5 billion in proceeds

by year-end 2023, with

approximately $2 billion sourced

from the Permian Basin.

As of year-end 2021, we have generated

$0.3 billion in

We also established a framework

for evaluating our assets and implementing

economic production curtailments considering

the weakness in oil

prices during the second quarter of 2020, which resulted

in taking an additional significant step of voluntarily

curtailing production, predominantly from

operated North American assets.

Due to our strong balance sheet,

we were in an advantaged position to forgo some production

and cash flow in anticipation of receiving higher

cash flows for those volumes in the future.

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

with 145 MBOED of the

curtailments from the Lower 48, 40 MBOED from

Alaska and 30 MBOED from our Surmont operation

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, certain

stay-at-home restrictions eased, which partially

restored lost demand, and WTI and Brent prices

second quarter around $40 per barrel.

Based on our economic framework, we began

restoring production from

voluntary curtailments in July, and with oil stabilizing around $40 per barrel, we

ended our curtailment

program during the third quarter.

Curtailments in the third quarter averaged approximately

90 MBOED, with

65 MBOED attributable to the Lower 48 and 15 MBOED

In August 2020, we acquired

additional Montney acreage for cash consideration

of $382 million, after

customary post-closing adjustments.

We also assumed $31 million in financing obligations for associated

partially owned infrastructure.

This acquisition consisted primarily

of undeveloped properties and included

140,000 net acres in the liquids-rich Inga Fireweed

asset Montney zone, which is directly adjacent

existing Montney position.

The transaction increased our Montney acreage

position to approximately 295,000

net acres with a 100 percent working interest.

See Note 4—Acquisitions and Dispositions in

Consolidated Financial Statements for additional

In October 2020, we announced an increase to our

quarterly dividend from $0.42 per share to $0.43

share repurchases before suspending our

share repurchase program upon entry into

our definitive

agreement to acquire Concho.

We resumed shares repurchases in February 2021 after completion of our

Concho acquisition.

We ended the year with over $12 billion of liquidity, comprised of $3.0 billion in cash

and cash equivalents, $3.6 billion in short-term

investments, and available borrowings under our credit

disposition proceeds.

The proceeds from these transactions will be used

in accordance with the company’s

priorities, including returns of capital to

shareholders and reduction of gross

In December 2021, we announced the initiation of a three-tier

return of capital framework.

This framework is

structured to continue delivering

a compelling, growing ordinary dividend and through

-cycle share repurchases.

includes the addition of a VROC tier.

The VROC tier will provide a flexible tool for

meeting our commitment of

returning greater than 30 percent

of cash from operating activities

during periods where commodity prices are

meaningfully higher than our planning price range.

We have set our expected

2022 total return of capital

three tiers at approximately

For more information on our three-tier return of capital framework, see

Capital Resources and Liquidity

Management’s Discussion and Analysis

ConocoPhillips

In 2021, we reaffirmed and improved

upon our commitment to ESG leadership

and excellence and the specific

targets we set in October 2020

when we became the first U.S.-based

oil and gas company to adopt

a Paris-aligned

climate-risk strategy.

Our commitment includes:

Net-zero ambition for

operational (scope 1 and 2) emissions

by 2050 with active advocacy for a price on

carbon to address end-use (scope 3) emissions;

a reduction in gross operated

and net equity operational GHG emissions intensity

percent from 2016 levels by 2030;

Zero routine flaring by 2030, with

an ambition to get there by 2025;

10 percent reduction target

for methane emissions intensity

by 2025 from a 2019 baseline, in addition to

the 65 percent reduction we have

made since 2015;

Adding continuous methane detection devices to

our operations, with an initial focus

on the larger Lower

48 facilities;

Dedicated low carbon technology

organization responsible

for identifying and prioritizing global emissions

reduction initiatives and opportunities associated

with the energy transition,

CCUS and hydrogen;

ESG performance factoring into

executive and employee compensation

this commitment, in December 2021, we announced that

approximately $0.2 billion of our 2022

company-wide capital expenditures

would be dedicated to energy transition

across the company’s

operations aimed at accelerating

the reduction of the company’s

scope 1 and 2 emissions and to pursue business

opportunities that address end-use emissions and

early-stage low-carbon

technology opportunities that leverage

the company’s adjacencies.

Operationally,

we remain focused on safely

executing the business.

Production increased 440 MBOED or 39

percent in 2021, compared to 2020.

Production excluding Libya

for 2021 was 1,527 MBOED.

After adjusting for

closed acquisitions and dispositions, impacts from 2020 curtailments,

2021 Winter Storm Uri and the conversion

Concho two-stream contracted

volumes to a three-stream basis,

production increased

by 28 MBOED or 2 percent.

This increase was primarily due to new production

from the Lower 48 and other development

programs across the

partially offset by normal field decline.

Production from Libya averaged

40 MBOED in 2021.

Management’s Discussion and Analysis

ConocoPhillips

Key Operating and Financial

Significant items during 2021 and recent

announcements included the following:

Announced an increase to expected 2022 return

of capital to shareholders

to a total of $8 billion, with the

incremental $1 billion to be distributed

through share repurchases and

Acquired and integrated

Concho, capturing over $1 billion

of synergies and savings ahead of schedule;

acquired Shell’s Permian

assets on December 1, 2021;

Exercised preemption right

to purchase an additional 10 percent

shareholding interest in APLNG,

expected to close in the first quarter

Generated $0.3 billion in disposition proceeds

from noncore sales and entered

into agreements

additional $1.8 billion in assets, subject to customary

closing adjustments;

Delivered strong operational

performance across the company’s

asset base, resulting in full-year

production of 1,527 MBOED, excluding

Achieved first production from

GMT2, Malikai Phase 2, SNP Phase 2;

Tor II project

production from a third Montney

multi-well pad;

Net cash provided by operating

activities was $17 billion, exceeding capital

expenditures and investments

of $5.3 billion;

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, we believe our decisive

actions over the last several years of focusing on free

cash flow generation, high-grading our asset

lowering the cost of supply of our investment

resource portfolio, and strengthening our

balance sheet have put

us in a strong relative position compared to our

independent E&P peers.

We remain committed to the core

principles of our value proposition, namely, free cash flow generation,

a strong balance sheet, commitment to

differential returns of and on capital,

and ESG leadership.

Our workforce and operations have adjusted to

mitigate the impacts of the COVID-19

operations in remote areas with confined spaces,

such as offshore platforms, the North Slope of Alaska,

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

restrictive measures before traveling to and working

Staffing levels in certain operating locations

have been reduced to minimize health risk exposure

and increase social distancing.

A portion of our office

staff have continued to work successfully remotely, with offices around the world carefully

designing and

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

These mitigation measures

have thus far been effective at reducing business operation

Workforce health and safety remains

the overriding driver for our actions and we have

demonstrated our ability to adapt to local

conditions as

The marketing and supply chain

side of our business has also adapted in response

commercial organization managed transportation commitments

during our voluntary curtailment program.

Our supply chain function is proactively working

with vendors to ensure the continuity of our business

operations, monitor distressed service and materials

providers, capture deflation opportunities, and pursue

reduction efforts.

We also enhanced our focus on counterparty risk monitoring during this period

requested credit assurances when applicable.

Operationally, we remain focused on safely executing the business.

In 2020, production of 1,127 MBOED

generated cash provided by operating activities

Distributed $6.0 billion to shareholders

through $2.4 billion in dividends and $3.6 billion of share

repurchases, representing

over 30 percent return of cash

provided by operating activities

to shareholders;

Ended the year with cash and cash equivalents

of $5.0 billion and short-term investments

of $0.4 billion,

We invested $4.7

billion into the business in

the form of capital expenditures, including $0.5

billion of acquisition capital, and paid dividends

shareholders of $1.8 billion.

Production decreased 221 MBOED or 16 percent

in 2020, compared to 2019.

Production excluding

Libya for 2020 was 1,118 MBOED.

Adjusting for estimated curtailments

approximately 80 MBOED;

closed acquisitions

and dispositions;

and excluding Libya, production for 2020

would have been 1,176 MBOED, a decrease of 15

MBOED compared with 2019 production.

This decrease

was primarily due to normal field decline, partly

offset by new wells online in the Lower 48, Canada,

Alaska and China.

Production from Libya averaged 9 MBOED

as it was in force majeure during a significant

portion of the year.

Key Operating and Financial Summary

Significant items during 2020 and recent announcements

included the following:

Enhanced both our portfolio and financial framework through the

acquisition of Concho in an all-stock

transaction, as well as purchasing bolt-on acreage in Canada and Lower

Full-year production, excluding Libya, of 1,118

curtailed approximately 80 MBOED during the

Cash provided by operating activities was $4.8 billion.

Generated $1.3 billion in disposition proceeds from non-core asset sales.

Distributed $1.8 billion in dividends and repurchased $0.9 billion of shares.

Ended the year with cash and cash equivalents totaling $3.0 billion and

short-term investments of $3.6

equaling $6.6 billion in ending cash and cash equivalents and short-term investments.

Announced two significant discoveries in Norway and achieved first production

appraisal drilling and started up first pads and related infrastructure

Adopted a Paris-aligned climate risk framework with ambition to achieve net

-zero operated emissions by

2050 as part of our commitment to ESG excellence.

Recognized impairments of proved and unproved properties totaling $1.3

billion after-tax.

totaling over $5.4 billion in ending cash

and cash equivalents and short-term investments

Initiated a paced monetization of the company’s

CVE investment, generating $1.1

billion in proceeds

through the sale of 117 million shares, with the funds applied to

share repurchases;

91 million CVE shares

remained outstanding at year

Advanced the company’s

net-zero ambition by

announcing an increase in scope 1 and 2 GHG emissions-

intensity reduction targets

to 40 to 50 percent from a 2016 baseline on

a net equity and gross operated

basis by 2030, from the previous target

of 35 to 45 percent on only a gross operated

Business Environment

Brent crude oil prices averaged $42 per barrel in 2020,

compared with $64 per barrel in 2019.

industry has periodically experienced this type

of volatility due to fluctuating supply-and-demand

and such volatility may persist for the foreseeable

Commodity prices are the most significant

impacting our profitability and related reinvestment

of operating cash flows into our business.

Our strategy is

to create value through price cycles by delivering

on the foundational principles that underpin our

free cash flow generation,

a strong balance sheet,

commitment to differential returns of and on

and ESG leadership.

Operational and Financial Factors Affecting

Profitability

The focus areas we believe will drive our success

through the price cycles include:

Free cash flow generation.

This is a core principle of our value proposition.

Our goal is to achieve

strong free cash flow by exercising capital discipline,

controlling our costs, and safely and reliably

delivering production.

Throughout the price cycles, we expect to make capital

investments sufficient

to sustain production.

Free cash flow provides funds that are available

to return to shareholders,

strengthen the balance sheet to deliver on our

priorities through the price cycles, or reinvest back into

the business for future cash flow expansion.

Maintain capital allocation discipline.

We participate in a commodity price-driven and

capital-intensive industry, with varying lead times from when an investment

decision is made

to the time an asset is operational and generates cash

Brent crude oil prices averaged

$71 per barrel in 2021, compared with $42 per barrel in

The energy industry

has periodically experienced this type of volatility

due to fluctuating supply-and-demand conditions

volatility may persist

in the future.

Commodity prices are the most significant factor

impacting our profitability

and related reinvestment

of operating cash flows into

our business.

Our strategy is to create

value through price

cycles by delivering on the financial principles that

underpin our value proposition;

balance sheet strength,

leading distributions, disciplined investments

and ESG excellence, all of which support

strong financial returns.

Balance sheet strength.

A strong balance sheet is a strategic

asset that provides flexibility through

We strive to maintain

-rating, and we have committed

to reducing gross debt by $5 billion

over the next five years.

This will reduce interest expense

and provide resilience in periods of volatility.

We ended the year with over

$5 billion in cash, maintaining balance sheet strength

even after completing

the all-cash acquisition of Shell’s

Permian assets.

Peer leading distributions.

We believe in delivering value

to our shareholders via our three-tiered

of capital framework,

which consists of a growing, sustainable

dividend, share repurchases, and

in 2022, the addition of VROC.

In 2021, we paid dividends on our common stock of approximately

billion and repurchased $3.6 billion of our common stock

partially sourced from our paced monetization

program related to the

CVE common shares owned.

Our combined dividends

and repurchases

represented over 30 percent

of our net cash provided by operating

Our first VROC of $0.20

cents per share was paid on January 14, 2022, to

shareholders of record as of January

will be made at the Board of Director’s

discretion, subject to market conditions

and other factors.

See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain

considerations.”

Management’s Discussion and Analysis

ConocoPhillips

Disciplined investments.

Our goal is to achieve strong

free cash flow by exercising capital

controlling our costs, and safely

and reliably delivering production.

We expect to make capital

investments sufficient to

sustain production throughout

the price cycles.

Free cash flow provides funds

that are available to return

to shareholders,

strengthen the balance sheet or reinvest

back into the

business for future cash flow expansion

Exercise capital discipline.

We participate in a commodity

price-driven and capital-intensive

industry, with varying

lead times from when an investment

decision is made to when an asset is

operational and generates

As a result, we must invest

significant capital dollars to explore for new oil

and gas fields, develop newly discovered

fields, maintain existing fields, and construct pipelines

and LNG facilities.

capital across a geographically diverse, low cost

of supply resource base, which combined

with legacy assets results in low production decline.

Cost of supply is the WTI equivalent

price that generates a 10 percent after-tax return

on a point-forward and fully burdened basis.

significant capital dollars to

develop newly discovered fields,

maintain existing fields, and construct

pipelines and LNG

We allocate capital

across a geographically diverse,

low cost of supply resource base,

which combined with legacy assets results

in low overall production decline.

Cost of supply is the

WTI equivalent price that generates

a 10 percent after-tax return

on a point-forward and fully

burdened basis.

Fully burdened includes capital infrastructure,

foreign exchange, price related inflation and

In setting our capital plans, we exercise a rigorous

approach that evaluates projects

using this cost of supply criteria, which we believe

will lead to value maximization and cash

flow expansion using an optimized investment

pace, not production growth for growth’s sake.

Our cash allocation priorities call for the investment

of sufficient capital to sustain production

and pay the existing dividend.

Additional capital may be allocated toward

discipline will be maintained.

In February 2021, we announced 2021 operating

plan capital for the combined company of

$5.5 billion.

The plan includes $5.1 billion to sustain current

production and $0.4 billion for

investment in major projects, primarily in

Alaska, in addition to ongoing exploration

appraisal activity.

The operating plan capital budget of $5.5 billion

is expected to deliver production from the

combined company of approximately 1.5 MMBOED

This production guidance

excludes Libya.

Control costs and expenses.

Controlling operating and overhead costs,

without compromising

safety and environmental stewardship, is a high priority.

We monitor these costs using

various methodologies that are reported to senior management

monthly, on both an absolute-

dollar basis and a per-unit basis.

Managing operating and overhead costs is

maintaining a competitive position in our industry, particularly in a low commodity

The ability to control our operating and overhead

costs impacts our ability to

deliver strong cash from operations.

In 2020, our production and operating expenses

percent lower than 2019, primarily due to decreased

wellwork and transportation costs

resulting from production curtailments across

our North American operated assets as well as

the absence of costs related to our U.K.

Australia-West divestitures.

information related to our U.K.

and Australia-West divestitures, see note 4—Acquisitions

Dispositions in the Notes to Consolidated Financial

At the time of the Concho acquisition announcement

in October 2020, we announced planned

cost reductions and quantified $350 million

of annual expense savings expected to be

achieved by 2022.

These reductions included approximately $150 million

due to streamlining

our internal organization to appropriate levels given the

current industry environment and

recent asset sales;

$100 million of G&A and

G&G due to a refocused exploration program;

and $100 million of redundant G&A costs on

a combined basis related to the Concho

Subsequent to the transaction announcement,

we identified $250 million of

further cost reductions from the combined companies

to be achieved by 2022.

foreign exchange,

cost of carbon,

price-related inflation and G&A.

In setting our capital plans, we exercise

a rigorous approach

that evaluates projects

using these cost of supply criteria, which we believe will

lead to value

maximization and cash flow expansion

using an optimized investment pace,

not production

growth for growth’s

Our cash allocation priorities call for

the investment of sufficient

capital to sustain production

and provide returns of capital

to shareholders.

Control our costs.

Controlling operating and overhead

costs, without compromising safety

environmental stewardship,

is a high priority.

Using various methodologies, we monitor these

costs monthly,

on an absolute-dollar basis and a per-unit basis

and report to management.

Managing operating and overhead costs

is critical to maintaining a competitive position

industry, particularly

in a low commodity price environment.

The ability to control our operating

and overhead costs positively impacts

our ability to deliver strong cash

from operations.

Optimize our portfolio.

In January 2021, we completed the acquisition

of Concho and

significantly increased our unconventional portfolio

with years of low cost of supply

The addition of complementary acreage in the

Delaware and Midland basins

creates a sizeable Permian presence to augment our leading

unconventional positions in the

Eagle Ford and Bakken in the Lower 48.

We added to our unconventional Montney position

with an asset acquisition that consisted primarily

of undeveloped properties directly adjacent

to our existing acreage.

These acquisitions followed several non-core asset

sales earlier in the year including

Australia-West in our Asia Pacific segment,

and Niobrara and Waddell Ranch in the Lower

We managed the portfolio well during a turbulent year, with asset sales entered at the end

of 2019 generating $1.3 billion of proceeds from dispositions

in the first half of 2020,

followed by opportunistic acquisitions of unconventional

assets in the second half of 2020

after commodity prices had dropped.

We will continue to evaluate our assets to determine

whether they compete for capital within our portfolio

and will optimize the portfolio as

necessary, directing capital towards the most competitive investments.

A strong balance sheet.

We believe balance sheet strength is critical in a cyclical business such as

Our strong operating performance buffered by a solid

balance sheet enables us to deliver on our

priorities through the price cycles.

Our priorities include execution of our

development plans,

maintaining a growing dividend, and returning competitive

returns of capital to shareholders.

Commitment to differential returns of and on capital.

We believe in delivering value to our

shareholders via a growing, sustainable dividend

supplemented by additional returns of

including share repurchases.

In 2020, we paid dividends on our common stock

of approximately $1.8

billion and repurchased $0.9

billion of our common stock.

Combined, our dividend and repurchases

57 percent of our net cash provided by operating

Since we initiated our current

share repurchase program in late 2016, we have repurchased

189 million shares for $10.5 billion,

which represents approximately 15 percent of shares

outstanding as of September 30, 2016.

December 31, 2020, $14.5 billion of repurchase

authority remained of the $25 billion share repurchase

program our Board of Directors had authorized.

Repurchases are made at management’s discretion,

at prevailing prices, subject to market conditions

and other factors.

See “Item 1A—Risk Factors Our

ability to declare and pay dividends and repurchase

shares is subject to certain considerations.”

In October 2020, we announced that our Board

of Directors approved an increase to our quarterly

dividend of $0.42 per share to $0.43 per share.

In February 2021, we resumed share repurchases

the completion of our Concho acquisition.

ESG Leadership.

Safety and environmental stewardship,

including the operating integrity of our

assets, remain our highest priorities, and we

are committed to protecting the health and

everyone who has a role in our operations and

the communities in which we operate.

conduct our business with respect and care for

both the local and global environment and

systematically manage risk to drive sustainable business

Demonstrating our commitment to

sustainability and environmental stewardship, in

October 2020, we announced our adoption of a Paris-

aligned climate risk framework as part of our continued

leadership in ESG excellence.

comprehensive climate risk strategy should enable

us to sustainably meet global energy demand while

delivering competitive returns through the energy transition.

We have set a target to reduce our gross

operated (scope 1 and 2) emissions intensity

by 35 to 45 percent from 2016 levels by 2030,

ambition to achieve net zero by 2050 for operated

We are advocating for reduction of

scope 3 end-use emissions intensity through our

support for a U.S.

carbon price and reaffirmed

commitment to the Climate Leadership Council.

We have joined the World

Bank Flaring Initiative to

work towards zero routine flaring of gas by 2030

and are the first U.S.-based oil and gas company

adopt a Paris-aligned climate risk strategy.

In 2021, we completed the acquisition of Concho and

Shell’s Permian

assets, significantly increasing our unconventional

portfolio with many additional years

cost of supply inventory.

The addition of this highly complementary acreage in the Midland

Delaware basins created

a sizeable Permian presence to augment

our leading unconventional

positions in the Eagle Ford and Bakken

in the Lower 48.

In our Asia Pacific segment, we notified

Origin Energy of our intent to exercise

our preemption right to purchase

an additional 10 percent

shareholding interest in

APLNG and announced the sale of our interests in

We continue to evaluate

our assets to determine whether they

compete for capital within

portfolio and optimize as necessary,

directing capital towards

the most competitive investments

and disposing of assets that don’t compete.

As such, in conjunction with our Shell Permian

acquisition announcement, we communicated

an increase in our planned disposition target

to $5 billion in proceeds by year-end

2023 as part of our ongoing portfolio high-grading

optimization efforts.

Add to our proved reserve base.

We primarily add to our proved reserve base in three ways:

Purchases of increased interests in existing

fields and acquisitions.

Application of new technologies and processes

to improve recovery from existing fields.

Successful exploration, exploitation and development

of new and existing fields.

As required by current authoritative guidelines,

the estimated future date when an asset will reach

end of its economic life is based on historical 12-month

first-of-month average prices and current

This date estimates when production will

end and affects the amount of estimated reserves.

Therefore, as prices and cost levels change from

year to year, the estimate of proved reserves also

Generally, our proved reserves decrease as prices decline and increase as prices

Reserve replacement represents the net change in

proved reserves, net of production, divided

current year production, as shown in our supplemental

reserve table disclosures.

replacement was negative 86 percent in 2020, reflecting

the impact of lower prices, which reduced

reserves by approximately 600 MMBOE.

Our organic reserve replacement, which excluded a net

decrease of 7 MMBOE from sales and purchases,

was negative 84 percent in 2020.

We primarily add to our proved

reserve base in three ways:

Acquire interest in existing

or new fields.

Apply new technologies and processes to

improve recovery from existing

Successfully explore, develop and exploit

new and existing fields.

As required by current authoritative

guidelines, the estimated future date

when an asset will

reach the end of its economic life is based on

historical 12-month first-of-month

average prices

and current costs.

This date estimates when production

will end and affects the amount of

estimated reserves.

Therefore, as prices and

cost levels change from year to year,

of proved reserves also changes.

Generally, our

proved reserves decrease as prices

increase as prices rise.

Management’s Discussion and Analysis

ConocoPhillips

Reserve replacement represents

the net change in proved reserves, net

of production, divided by

our current year production, as

shown in our supplemental reserve table disclosures.

reserve replacement was 377 percent

in 2021, reflecting a net increase from purchases

as well as higher prices.

Our organic reserve replacement,

which excluded a net increase of

1,115 MMBOE from sales and purchases, was

189 percent in 2021.

In the three years ended December 31, 2021, our reserve

replacement was 59 percent, primarily

impacted by lower prices in 2020.

Our organic reserve replacement during the three years

December 31, 2020, which excluded

a net increase of 89 MMBOE related to sales

and purchases, was

Access to additional resources may become increasingly

difficult as commodity prices can make

replacement was 155 percent.

organic reserve replacement

during the three years ended December 31, 2021, which

net increase of 1,022 MMBOE related

to sales and purchases, was 88 percent.

Access to additional resources may become

increasingly difficult as commodity prices can

projects uneconomic or unattractive.

In addition, prohibition of direct investment

in some nations,

national fiscal terms, political instability, competition from national oil companies,

and lack of access

to high-potential areas due to environmental or other

regulation may negatively impact our

increase our reserve base.

As such, the timing and level at which we add

to our reserve base may, or

may not, allow us to replace our production

over subsequent years.

Apply technical capability.

We leverage our knowledge and technology to create value and safely

deliver on our plans.

Technical strength is part of our heritage and allows us to economically

additional resources to reserves, achieve greater

operating efficiencies and reduce our environmental

Companywide, we continue to leverage knowledge

of technological successes across our

We have embraced the digital transformation and are using digital innovations to

work and operate

more efficiently.

Predictive analytics have been adopted in our operations

and planning process.

Artificial intelligence, machine learning and

deep learning are being used for emissions

seismic advancements and advanced controls in

our field operations.

Attract, develop and retain a talented work force.

We strive to attract, develop and retain individuals

with the knowledge and skills to successfully

execute our business strategy in a manner

our core values and ethics.

We offer university internships across multiple disciplines to attract the

best early career talent.

We also recruit experienced hires to fill critical skills and maintain a broad

range of expertise and experience.

We promote continued learning, development and technical

training through structured development programs

designed to enhance the technical and functional

skills of our employees.

Other Factors Affecting

Profitability

Other significant factors that can affect our profitability

nations, national fiscal terms, political

competition from national oil companies,

lack of access to high-potential areas due to

environmental or other regulation

may negatively

impact our ability to increase our reserve base.

As such, the timing and level at which we add to

our reserve base may,

or may not, allow us to fully replace our

production over subsequent

ESG Leadership.

Safety and environmental

stewardship, including the operati

onal integrity of our assets,

remain our highest priorities.

We are committed to

protecting the health and safety

of everyone who has

a role in our operations and the communities

in which we operate.

We strive to conduct

with respect and care for the local

and global environment and systematically

manage risk to drive

sustainable business operations.

In September 2021, we reaffirmed and improved

upon our commitment

to ESG leadership and excellence

and the specific targets that we set in

October 2020 when we became

the first U.S.

based oil and gas

company to adopt a Paris-aligned

climate-risk strategy.

comprehensive energy transition

strategy is designed to sustainably

meet global energy demand while

delivering competitive returns on and

of capital through the energy transition.

Our strategy also

recognizes the importance of

reducing society’s end-use emissions

to meet global climate goals.

active only in the upstream side of the business, we do not

produce end-use products

directly for consumers.

We believe that if everyone

addressed their scope 1 and 2 emissions, scope

would also be addressed.

This is why we have consistently

taken a prominent role

in advocating that

scope 3 emissions be addressed through a well-designed

economywide price on carbon.

In addition, we

are making early-stage investments

in transition opportunities with the potential

to generate competitive

returns that will help address end-use emissions,

including CCUS and Hydrogen.

We are also engaging

with our supply chain on their emissions targets.

Other significant factors that

can affect our profitability

Energy commodity prices.

Our earnings and operating cash flows generally

correlate with industry

price levels for crude oil and natural gas.

Industry price levels are subject to factors external

company and over which we have no control, including

but not limited to global economic health,

supply disruptions or fears thereof caused by civil

unrest or military conflicts, actions taken by

and other producing countries, environmental laws,

tax regulations, governmental policies and

weather-related disruptions.

The following graph depicts the average benchmark

prices for WTI

crude oil, Brent crude oil and U.S.

Henry Hub natural

Brent crude oil prices averaged $41.68 per barrel

in 2020, a decrease of 35 percent compared

correlate with crude oil and

natural gas commodity prices.

Commodity price levels are subject to factors

external to the company and

over which we have no control,

including but not limited to global economic health, supply

disruptions or

fears thereof caused by civil unrest

or military conflicts, actions taken

by OPEC Plus and other producing

countries, environmental

laws, tax regulations,

governmental policies, global pandemics and

related disruptions.

The following graph depicts the average

benchmark prices for WTI crude oil, Brent

crude oil and U.S.

Henry Hub natural gas

over the past three years:

Management’s Discussion and Analysis

ConocoPhillips

Brent crude oil prices averaged

$70.73 per barrel in 2021, an increase of 70 percent compared

$41.68 per barrel in 2020.

Similarly, WTI crude oil prices decreased 31 percent from $57.02 per

barrel in 2019 to $39.37 per barrel in 2020.

Crude oil prices were lower due to the dual

supply shocks.

The demand shock was triggered by the

COVID-19 pandemic, which continues to

have unprecedented social and economic consequences.

The supply shock was triggered by

disagreements between OPEC and Russia, beginning

in early March 2020, which resulted in

significant supply coming onto the market

and created higher inventory levels.

Henry Hub natural gas prices

decreased 21 percent from an average of $2.63

per MMBTU in 2019 to

Similarly, WTI crude oil prices

increased 72 percent from $39.37

per barrel in

2020 to $67.92 per barrel in 2021.

Following COVID-19 economic shutdowns

in early 2020, global oil

demand increased steadily through

the year alongside the global economic recovery.

restraint, capital

discipline by U.S.

E&P’s and various

unplanned supply disruptions in producing countries

moderated supply growth,

reducing excess global inventories

and putting upward pressure

on global oil

Henry Hub natural gas prices increased

85 percent from an average

of $2.08 per MMBTU in 2020 to $3.85

per MMBTU in 2021.

Henry Hub prices were depressed due to high

storage levels and weak

Our realized bitumen price decreased 75 percent

from an average of $31.72 per barrel

in 2019 to $8.02

Extreme weather events in many

parts of the world and several global LNG

liquefaction outages depleted

global natural gas inventories

in early 2021, generating strong

LNG exports and supporting robust

domestic demand.

Our realized bitumen price increased 368 percent

from an average of $8.02

per barrel in 2020 to $37.52

per barrel in 2021.

The decrease was largely driven by weakness in WTI,

reflective of impacts from

the COVID-19 pandemic.

The WCS differential to WTI at Hardisty remained fairly

curtailment orders imposed by the Alberta Government,

which limited production from the province,

continued throughout 2020.

We continue to optimize bitumen price realizations through

improvements in alternate blend capability which

results in lower diluent costs and access

Gulf Coast market through rail and pipeline contracts.

Our worldwide annual average realized price decreased

34 percent from $48.78

The increase was largely driven

by strength in WTI, reflective

of increasing global

demand and OPEC discipline.

The WCS differential to WTI at

Hardisty remained fairly flat as

production offsets incremental

pipeline capacity.

We continue to optimize

bitumen price realizations

through improvements in alternate

blend capability which results in lower diluent

costs and access to the

Gulf Coast market through

rail and pipeline contracts.

Our worldwide annual average

realized price increased 70 percent

per BOE in 2020 to $54.63

per BOE in 2020 primarily due to lower realized

oil, natural gas and bitumen prices.

North America’s energy supply landscape has been transformed from one of resource

scarcity to one

of abundance.

In recent years, the use of hydraulic fracturing

and horizontal drilling in

unconventional formations has led to increased industry

actual and forecasted crude oil and natural

gas production in the U.S.

per BOE in 2021 primarily due to higher realized oil,

natural gas and bitumen prices.

North America’s energy

supply landscape has been transformed

from one of resource scarcity

In recent years, the use of hydraulic

fracturing and horizontal

drilling in unconventional

formations has led to increased

industry actual and forecasted

crude oil and natural gas production

Although providing significant short

and long-term growth opportunities

for our company, the increased abundance of crude oil and natural gas due to development

unconventional plays could also have adverse financial

implications to us, including:

period of low commodity prices;

and long-term growth opportunities for

increased abundance of crude oil and natural

gas due to development of unconventional

plays could also

have adverse financial implications

to us, including:

an extended period of low commodity

production curtailments;

and delay of plans to develop areas such as

unconventional fields.

Should one or more of these events occur, our revenues would

be reduced, and

additional asset impairments might be possible.

We participate in a capital-intensive industry.

of plans to develop areas such as unconventional

or more of these events occur,

our revenues would be reduced, and

additional asset impairments might

Management’s Discussion and Analysis

ConocoPhillips

We participate in a capital

-intensive industry.

At times, our PP&E and investments

become impaired when, for example, commodity

prices decline significantly for long

periods of time,

our reserve estimates are revised downward, or a

decision to dispose of an asset leads to

impaired when, for example,

commodity prices decline significantly for long periods

of time, our reserve

estimates are revised downward,

a decision to dispose of an asset leads to a write-down

to its fair value,

We may also invest large amounts of money in exploration which, if exploratory

drilling proves unsuccessful, could lead to a material

impairment of leasehold values.

As we optimize

our assets in the future, it is reasonably possible

we may incur future losses upon sale or

charges to long-lived assets used in operations, investments

in nonconsolidated entities accounted for

under the equity method, and unproved properties.

For additional information on our impairments,

see Note 7—Suspended Wells and Exploration Expenses and Note 8—Impairments, in

Consolidated Financial Statements.

or the current fair value of an investment

is less than its carrying amount and the loss in value is deemed

other than temporary.

As we optimize our assets in the future, it is reasonably

possible we may incur

future losses upon sale or impairment charges to

long-lived assets used in operations,

investments in

nonconsolidated entities accounted

for under the equity method, and unproved

information on our impairments,

Effective tax rate

Our operations are in countries with different tax rates

Our operations are in countries

with different tax rates

and fiscal structures.

Accordingly, even in a stable commodity price and fiscal/regulatory environment,

effective tax rate can vary significantly between periods

based on the “mix” of before-tax earnings

within our global operations.

even in a stable commodity price and fiscal/regulatory

environment, our overall

effective tax

rate can vary significantly

between periods based on the “mix” of before-tax

earnings within our global

Fiscal and regulatory environment

Our operations can be affected by changing economic,

and political environments in the various countries

in which we operate, including the U.S.

unrest or strained relationships with governments

may impact our operations or investments.

changing environments could negatively impact our

results of operations, and further changes to

increase government fiscal take could have a

negative impact on future operations.

Our management

carefully considers the fiscal and regulatory

environment when evaluating projects or

determining the

levels and locations of our activity.

Our operations can be affected

by changing economic, regulatory

and political

environments in the various countries

in which we operate, including civil unrest

relationships with governments

that may impact our operations or

These changing

environments could negatively

impact our results of operations, and further changes

government fiscal take

could have a negative

impact on future operations.

Our management carefully

considers the fiscal and regulatory

environment when evaluating

projects or determining the levels and

locations of our activity.

Production and Capital

In February 2021, we announced 2021 operating

plan capital for the combined company of $5.5

plan includes $5.1 billion to sustain current

production and $0.4 billion for investment

in major projects,

primarily in Alaska, in addition to ongoing

exploration appraisal activity.

The operating plan capital budget of $5.5 billion

is expected to deliver production from the combined

of approximately 1.5 MMBOED in 2021.

This production guidance excludes Libya.

Restructuring

As a result of the acquisition of Concho, we commenced

a restructuring program in the first quarter

association with combining the operations of the

two companies.

We expect to incur significant non-recurring

transaction and acquisition-related costs in

2021 for employee severance payments;

benefit costs related to the workforce reductions;

retention costs;

employee relocations;

financial, legal, and accounting advisors;

We currently cannot estimate these costs, as well as

other unanticipated items,

and expect to recognize the majority

of these expenses in the first quarter of 2021.

2022 operating plan capital budget

is $7.2 billion.

The plan includes funding for ongoing development

programs, major projects, exploration

and appraisal activities, base maintenance and

$0.2 billion for projects to

reduce the company’s

scope 1 and 2 emissions intensity and investme

nts in several early-stage

opportunities that address end-use emissions.

Production guidance is 1.8 MMBOED in 2022 including Libya

but excluding the impacts from the pending

disposition and acquisition of additional APLNG shareholding interest.

First quarter 2022 production

is expected to

be 1.75 MMBOED to 1.79 MMBOED.

Operating Segments

We manage our operations through six operating segments, which are primarily

defined by geographic region:

Europe, Middle East

and North Africa;

We manage our operations

through six operating segments,

which are primarily defined by geographic

Europe, Middle

East and North Africa;

Asia Pacific;

and Other International.

Corporate and Other represents income and costs

not directly associated with an operating

segment, such as

most interest expense, premiums incurred on the

early retirement of debt, corporate overhead,

technology activities, as well as licensing revenues.

Our key performance indicators, shown in the statistical

tables provided at the beginning of the operating

segment sections that follow, reflect results from our operations, including commodity

prices and production.

Other International.

Corporate and Other represents

income and costs not directly associated

with an operating segment, such as most

interest expense, premiums

incurred on the early retirement

of debt, corporate overhead,

certain technology

activities, as well as licensing revenues.

Our key performance indicators,

shown in the statistical tables provided

at the beginning of the operating segment

sections that follow,

reflect results from our operations,

including commodity prices and production.

Results of Operations

Effective with the third quarter of 2020, we have restructured our segments to align with

changes to our

internal organization.

The Middle East business was realigned from the Asia Pacific and Middle East

to the Europe and North Africa segment.

The segments have been renamed the Asia Pacific

segment and the

Europe, Middle East and North Africa segment.

We have revised segment information disclosures and

segment performance metrics presented within our results of operations for the

current and prior years.

This section of the Form 10-K

discusses year-to-year comparisons between 2020

For discussion of

year-to-year comparisons between 2019 and 2018, see

"Management's Discussion and Analysis

Condition and Results of Operations" in Exhibit

, Item 7 filed with our Form 8-K filed

on November 16,

ConocoPhillips

Results of Operations

This section of the Form 10-K discusses year-to-year comparisons

between 2021 and 2020.

For discussion of year-

to-year comparisons between 2020 and 2019, see "Management's

Discussion and Analysis of Financial Condition

and Results of Operations" in Part II, Item

7 of our 2020 10-K.

Consolidated Results

A summary of the company’s net income (loss) attributable to ConocoPhillips

A summary of the company’s net

income (loss) attributable to ConocoPhillips

by business segment follows:

Millions of Dollars

Years Ended December 31

Europe, Middle East and North Africa

1 unchanged sentence

Corporate and Other

Net income (loss) attributable to ConocoPhillips

decreased $9.9 billion in 2020.

The decrease was mainly due

Lower realized commodity prices.

Lower sales volumes due to normal field decline,

asset dispositions and production curtailments.

additional information related to dispositions,

see Note 4—Asset Acquisitions and Dispositions

Notes to Consolidated Financial Statements.

The absence of a $2.1 billion after-tax gain associated

with the completion of the sale of two

ConocoPhillips U.K.

subsidiaries.

For additional information, see Note 4—Asset

Acquisitions and

Dispositions in the Notes to Consolidated Financial

An unrealized loss of $855 million after-tax

on our Cenovus Energy (CVE) common shares in 2020,

as compared to a $649 million after-tax unrealized

gain on those shares in 2019.

A $648 million after-tax impairment for the associated

carrying value of capitalized undeveloped

leasehold costs and an equity method investment

related to our Alaska North Slope Gas

additional information, see Note 7—Suspended

Wells and Exploration Expenses, in the Notes to

Consolidated Financial Statements.

Increased impairments

primarily related to developed properties

in our non-core assets which were

written down to fair value due to lower commodity

prices and development plan changes.

additional information, see Note 8—Impairments

and Note 14—Fair Value Measurement in the Notes

to Consolidated Financial Statements.

The absence of other income of $317 million after-tax

related to our settlement agreement with

These decreases in net income (loss) were partly

Lower production and operating expenses, primarily

due to the absence of costs related to our U.K.

and Australia-West divestitures and decreased wellwork and transportation costs

resulting from

production curtailments across our North American

operated assets.

A $597 million after-tax gain on dispositions related

to our Australia-West divestiture.

Lower DD&A expenses, primarily due to lower

volumes related to normal field decline and

production curtailments as well as impacts

of our Australia-West and U.K.

divestitures.

offsetting this decrease, was higher DD&A expenses

due to price-related downward reserve revisions.

Net income (loss) attributable to

ConocoPhillips

Net Income (loss) attributable to

ConocoPhillips increased $10.8 billion in 2021.

2021 earnings were positively

Higher realized commodity prices.

Higher sales volumes primarily due to our Concho acquisition and

absence of production curtailments.

A gain of $1,040 million after-tax on our

Cenovus Energy (CVE) common shares in 2021, as

compared to a

$855 million after-tax loss on those shares

Lower exploration expenses

Absence of a 2020 impairment for $648 million after

-tax for the entire carrying value

capitalized undeveloped leasehold

costs related to our Alaska

North Slope Gas asset.

Lower dry hole expenses.

Absence of early cancellation of our 2020 winter exploration

program in Alaska.

Absence of unproved property

impairment and dry hole expenses in 2020 for the Kamunsu

Field in Malaysia, which is no longer in our development

Higher equity in earnings of affiliates, primarily due to

higher LNG sales prices.

Contingent payments related

to prior dispositions in our Canada and Lower 48 segments.

An after-tax gain of $194 million recognized

for a FID bonus associated with our Australia

-West divestiture

Lower impairments, primarily due to the absence

of impairments recognized in 2020 for

noncore assets in

our Lower 48 segment partially offset

by an impairment in our APLNG investment

included within our Asia

Pacific segment.

These increases in net income (loss) were partly

Higher production and operating expenses

and taxes other than income taxes,

primarily due to higher

sales volumes.

Higher DD&A expenses caused by higher production

volumes, partially offset by lower rates

positive reserve revisions due to higher

commodity prices in 2021.

Absence of a $597 million after-tax gain

on our Australia-West

divestiture completed in May

Restructuring and transaction expenses

of $341 million after-tax associated

with the Concho and Shell

acquisitions in addition to mark-to-market

impacts on certain key employee

compensation programs.

Results of Operations

ConocoPhillips

Realized losses on hedges of $233 million after

-tax related to derivative

positions assumed through our

Concho acquisition.

These derivative positions were settled

entirely within the first quarter of 2021.

Income Statement Analysis

Sales and other operating revenues decreased 42 percent

in 2020, mainly due to lower realized commodity

prices and lower sales volumes.

Sales volumes decreased due to normal field

decline, production curtailments

from our North American operated assets and the

divestiture of our U.K.

assets in the third

quarter of 2019 and

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

Equity in earnings of affiliates decreased $347 million

in 2020, primarily due to lower earnings from

APLNG because of lower LNG prices.

Partly offsetting this decrease was the absence

of impairments related

to equity method investments in our Lower 48 segment

of $155 million and the absence of a $118 million

deferred tax adjustment at QG3, reported in our

Unless otherwise indicated, all results in Income Statement

Analysis are before-tax.

Sales and other operating revenues

increased 144 percent in 2021, mainly due to higher

realized commodity prices

and higher sales volumes.

Equity in earnings of affiliates increased

$400 million in 2021, primarily due to higher earnings driven

LNG and crude prices, partially offset by a higher

effective tax rate

related to equity method investments

Europe, Middle East and North Africa segment

Gain on dispositions decreased $1.4 billion in

2020, primarily due to the absence of a $1.7 billion

gain associated with the completion of the sale

of two ConocoPhillips U.K.

subsidiaries.

Partly offsetting the

decrease was a $587 million before-tax gain associated

with our Australia-West divestiture.

information related to these dispositions, see Note

4—Asset Acquisitions and Dispositions

in the Notes to

Consolidated Financial Statements.

Other income (loss) decreased $1.9 billion

in 2020, primarily due to a before-tax unrealized

million on our CVE common shares in 2020, and

the absence of a $649 million before-tax unrealized

Gain on dispositions decreased $63 million in 2021, primarily due

to the absence of a $587 million gain related

our 2020 Australia-West

divestiture and a $179 million loss associated

with the sale of noncore assets in our Other

International segment.

The decreases were partially offset

by $200 million related to a FID bonus

associated with

our Australia-West

gains recognized for contingent

payments associated with previous

dispositions in

our Canada and Lower 48 segments and gains

on sales of certain noncore assets in our Lower 48 segment.

Other income (loss) increased $1.7 billion in 2021, primarily due

to a gain of $1,040 million on our CVE common

shares in 2021, as compared to a $855 million loss on

those shares in 2020.

Additionally, other income (loss) decreased due to the absence of $325 million

tax related to our settlement agreement with PDVSA.

For discussion of our CVE 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

Purchased commodities decreased 32 percent in

2020, primarily due to lower natural gas

and crude oil prices;

lower crude oil and natural gas volumes purchased;

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.

Production and operating expenses decreased $978

million in 2020, primarily due to reduced activities

transportation costs associated with lower activity

across our North American operated assets in

the low commodity price environment and the

absence of costs related to our U.K.

and Australia-West

divestitures.

Selling, general and administrative expenses decreased

$126 million in 2020, primarily due to lower

associated with compensation and benefits,

Purchased commodities increased 125 percent

in 2021, primarily in line with higher gas and crude prices

Production and operating expenses

increased $1,350 million in 2021, primarily in line with higher production

Selling, general and administrative

expenses increased $289 million in 2021, primarily due to

transaction and

restructuring expenses associated

with our Concho acquisition and higher compensation and benefits

including mark-to-market impacts of certain

compensation programs.

Exploration expenses increased $714 million

in 2020, primarily due to an $828 million before-tax

for the entire carrying value of capitalized undeveloped

leasehold costs related to our Alaska

North Slope Gas

Partly offsetting this increase, was the absence of

a $141 million before-tax leasehold impairment

expense due to our decision to discontinue exploration

activities in the Central Louisiana Austin

For additional information, see Note 7—Suspended

Wells and Exploration Expenses, in the Notes to

Consolidated Financial Statements.

Impairments increased $408 million in

2020, primarily related to developed properties

in our non-core assets

which were written down to fair value due to lower

commodity prices and development plan changes.

additional information, see Note 8—Impairments

and Note 14—Fair Value Measurement in the Notes to

Consolidated Financial Statements.

Taxes other than income taxes decreased $199 million in 2020, primarily due

to lower commodity prices and

Foreign currency transaction (gains) losses decreased

$138 million in 2020, due to gains recognized

foreign currency derivatives and other foreign

currency remeasurements.

For additional information, see Note

13—Derivative and Financial Instruments

in the Notes to Consolidated Financial Statements.

See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements,

for information regarding our

income tax provision (benefit) and effective tax rate.

key employee compensation

Exploration expenses decreased

$1,113 million in 2021, primarily due to the absence of 2020 expenses

an $828 million impairment for the entire

carrying value of capitalized

undeveloped leasehold costs related

Alaska North Slope Gas asset, the early cancellation of our

2020 winter exploration

program in Alaska, and

of unproved property impairment and

dry hole expenses from 2020 for the Kamunsu

East Field in Malaysia.

also saw lower dry hole expenses in Alaska.

Impairments decreased $139 million in 2021, primarily due

to the absence of impairments recognized

noncore assets in our Lower 48 segment partially

offset by an impairment in our APLNG investment

within our Asia Pacific segment in 2021.

For additional information,

other than income taxes increased

$880 million in 2021, caused primarily by higher commodity prices and

higher Lower 48 sales volumes.

Foreign currency transaction

(gains) losses decreased $50 million in 2021 due to the

absence of derivative gains

and other remeasurements.

Note 17—Income Taxes

for information regardin

our income tax provision

and effective tax rate.

Results of Operations

ConocoPhillips

Summary Operating Statistics

3 unchanged sentences

Equity affiliates

Total crude oil

Natural gas liquids (MBD)

1 unchanged sentence

Equity affiliates

Total natural gas liquids

natural gas liquids

Bitumen (MBD)

2 unchanged sentences

Equity affiliates

Total natural gas

Total Production

4 unchanged sentences

Equity affiliates

Total crude oil

Natural gas liquids (per bbl)

1 unchanged sentence

Equity affiliates

Total natural gas liquids

natural gas liquids

Bitumen (per bbl)

2 unchanged sentences

Equity affiliates

Total natural gas

Millions of Dollars

Worldwide Exploration Expenses

Worldwide Exploration

General and administrative;

2 unchanged sentences

Leasehold impairment

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

At December 31, 2020, our operations were

producing in the U.S., Norway, Canada, Australia,

Indonesia, China, Malaysia, Qatar and Libya.

Total production, including Libya, of 1,127 MBOED decreased 221 MBOED or 16

percent in 2020 compared

Exploration Expenses

Results of Operations

ConocoPhillips

We explore for,

produce, transport and market

crude oil, bitumen, natural gas,

LNG and NGLs on a worldwide

At December 31, 2021, our operations

were producing in the U.S., Norway,

Canada, Australia, Indonesia,

China, Malaysia, Qatar and Libya.

Total production,

including Libya, of 1,567 MBOED increased 440 MBOED or 39 percent

in 2021 compared with

2020, primarily due to:

Higher volumes in Lower 48 due to our Concho acquisition

New wells online in Lower 48, Canada, Norway,

Malaysia and Alaska.

Absence of production curtailments,

primarily in our North American assets.

Higher production in Libya due to the absence of a

forced shutdown of the Es Sider export

other eastern export terminals.

Improved well performance in

Canada, Alaska and China.

The increase in production during 2021 was partly

Normal field decline.

The divestiture of our U.K.

assets in the third

quarter of 2019 and our Australia-West assets in the

second quarter of 2020.

Production curtailments of approximately 80 MBOED,

primarily from North American operated

assets and Malaysia, in response to the low crude

oil price environment.

Less production in Libya due to the forced shutdown

of the Es Sider export terminal and other

export terminals after a period of civil unrest.

The decrease in production during 2020 was partly

New wells online in the Lower 48, Canada,

Norway, Alaska and China.

Production excluding Libya for 2020 was 1,118 MBOED.

Adjusting for estimated curtailments

approximately 80 MBOED and closed acquisitions

and dispositions, production for 2020 would

1,176 MBOED, a decrease of 15 MBOED compared

This decrease was primarily due to normal

field decline, partly offset by new wells online in the

Lower 48, Canada, Norway, Alaska and China.

Production from Libya averaged 9 MBOED as it

was in force majeure during a significant portion

Net Income (Loss) Attributable to ConocoPhillips

(millions of dollars)

Absence of production from Australia

-West due to our second quarter

2020 disposition.

Production excluding Libya

for 2021 was 1,527 MBOED.

After adjusting for closed acquisitions

and dispositions,

impacts from 2020 curtailments, 2021 Winter

Storm Uri and the conversion

of Concho two-stream contracted

volumes to a three-stream basis,

production increased by 28 MBOED or 2 percent.

This increase was primarily due

to new production from the Lower 48 and other

development programs across

the portfolio,

partially offset by

normal field decline.

Production from Libya

averaged 40 MBOED in 2021.

Results of Operations

ConocoPhillips

Net Income (Loss) Attributable

to ConocoPhillips

Average Net Production

6 unchanged sentences

Natural gas ($ per mcf)

The Alaska segment primarily explores for, produces, transports

and markets crude oil, NGLs and natural gas.

In 2020, Alaska contributed 28 percent of our consolidated

liquids production and less than 1 percent of our

consolidated natural gas production.

The Alaska segment primarily explores for,

produces, transports and markets

crude oil, NGLs and natural gas.

2021, Alaska contributed 19 percent

of our consolidated liquids production

and less than 1 percent of our

consolidated natural

gas production.

Net Income (Loss) Attributable to ConocoPhillips

Alaska reported a loss of $719 million in

2020, compared with earnings of $1,520 million

were negatively impacted by:

Lower realized crude oil prices.

A $648 million after-tax impairment associated

with the carrying value of our Alaska North Slope

For additional information, see Note 7—Suspended

Wells and Exploration Expenses, in the

Notes to Consolidated Financial Statements.

Lower sales volumes, primarily due to normal field

decline and production curtailments

operated assets on the North Slope—the Greater

Kuparuk Area (GKA) and Western North Slope

Higher DD&A expenses, primarily from

increased DD&A rates due to price-related downward

reserve revisions, partly offset by lower production

Increased exploration expenses, primarily

due to higher dry hole costs and expenses related

early cancellation of our winter exploration program.

Earnings were positively impacted by:

Lower production and operating expenses, primarily

associated with lower transportation and

terminaling costs as well as lower activities

across our assets.

Average production decreased 20 MBOED in 2020 compared with 2019, primarily

Alaska reported earnings of $1,386 million in 2021, compared

with a loss of $719 million in 2020.

Earnings were

positively impacted by:

Higher realized crude oil prices.

Absence of 2020 exploration expenses

including a $648 million after-tax impairment

associated with the

carrying value of our Alaska North Slope Gas assets

and the early cancellation of our winter exploration

Lower dry hole expenses.

Earnings were negatively

Higher taxes other than income taxes

primarily due to higher realized crude oil prices.

Average production

decreased 1 MBOED in 2021 compared with 2020, primarily

Normal field decline.

Production curtailments at our operated assets on

the North Slope—GKA and WNS—of 8 MBOED

in response to the low crude oil price environment.

These production decreases were partly offset by:

Lower downtime due to the absence of planned

turnarounds at the Greater Prudhoe Area.

New wells online at our operated assets on the

North Slope—GKA and WNS.

Net Income (Loss) Attributable to ConocoPhillips

(millions of dollars)

The production decrease was partly

Absence of curtailments.

Improved production at

our Western North Slope assets

as a result of net royalty interest

associated with periodic redetermination.

Improved performance in the Greater

Prudhoe Area and Western

North Slope assets.

New wells online across the segment.

Results of Operations

ConocoPhillips

Net Income (Loss) Attributable

to ConocoPhillips

Average Net Production

7 unchanged sentences

Natural gas ($ per mcf)**

The Lower 48 segment consists of operations located

in the contiguous U.S.

and the Gulf of Mexico.

2020, the Lower 48 contributed 40 percent of our

consolidated liquids production and 44 percent of

consolidated natural gas production.

*Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021.

**Average sales prices, including the impact of hedges settling per initial contract terms in the first quarter of 2021 assumed in our

acquisition were $65.19 per barrel for crude oil and $4.33 per mcf for natural gas for the

year ended December 31, 2021.

As of March 31, 2021,

we had settled all oil and gas hedging positions acquired from Concho.

The Lower 48 segment consists of operations

located in the contiguous U.S.

the Gulf of Mexico.

the Lower 48 contributed 55 percent

of our consolidated liquids production

and 64 percent of our consolidated

natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

Lower 48 reported a loss of $1,122 million in 2020,

compared with earnings of $436 million

Earnings were negatively impacted by:

Lower realized crude oil, NGL and natural gas prices.

Lower crude oil sales volumes due to normal

field decline and production curtailments.

Higher impairments, primarily related to developed

properties in our non-core assets which were

written down to fair value due to lower commodity

Lower 48 reported earnings of $4,932 million in 2021, compared

with a loss of $1,122 million in 2020.

were positively impacted by:

Higher realized crude oil, NGL and natural

Higher sales volumes due to our Concho acquisition and the absence

of production curtailments.

Lower impairments, primarily related

to developed properties in our noncore

assets which were written

down to fair value due to lower commodity

prices and development plan changes.

8—Impairments and Note 14—Fair Value Measurement, for additional information.

Earnings were positively impacted by:

Lower exploration expenses, primarily

due to the absence of a combined $197 million

leasehold impairment and dry hole costs associated

with our decision to discontinue exploration

activities in the Central Louisiana Austin

Lower DD&A expenses, primarily due to normal

field decline and production curtailments,

offset by increased DD&A rates due to price-related downward

reserve revisions.

Lower production and operating expenses, primarily

due to lower activities driven by production

curtailments in response to the low price environment

and disposition impacts.

Lower taxes other than income taxes, primarily

due to lower realized prices and volumes.

Total average production decreased 66 MBOED in 2020 compared with 2019,

primarily due to:

Higher gains on dispositions related to

selling our interests in certain noncore

Earnings were negatively

Higher DD&A expenses, production and operating

expenses and taxes other than

income taxes primarily

due to higher production volumes.

Partially offsetting the increase

in DD&A expenses were lower rates

from price-related reserve revisions.

Impacts resulting from our Concho acquisition,

including higher selling, general and administrative

expenses for transaction and restructuring

charges, as well as realized losses

on derivative settlements.

average production

increased 395 MBOED in 2021 compared with 2020, primarily

Higher volumes due to our Concho acquisition.

New wells online from our development programs

in Permian, Eagle Ford

Absence of curtailments.

These production increases were partly

Normal field decline.

Production curtailments of approximately 55 MBOED

in response to the low crude oil price

These production decreases were partly offset by:

New wells online from the Eagle Ford, Permian and

Net Income (Loss) Attributable to ConocoPhillips

(millions of dollars)

Results of Operations

ConocoPhillips

Net Income (Loss) Attributable

to ConocoPhillips

Average Net Production

11 unchanged sentences

**Average prices for sales of bitumen produced 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.

optimization of our pipeline capacity between Canada and the U.S.

Our Canadian operations consist of the Surmont

oil sands development in Alberta and the liquids-rich

Montney unconventional play in British Columbia.

oil sands development in Alberta and the liquids-rich Montney

unconventional play in

British Columbia.

In 2021, Canada contributed 8 percent of our

liquids production and 3 percent of our consolidated

consolidated liquids

production and 4 percent of our consolidated

natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

Canada operations reported a loss of $326 million

in 2020 compared with earnings of $279 million

Earnings decreased mainly due to:

Lower realized bitumen prices.

Higher DD&A expenses, primarily due to increased volumes and DD&A rates

from Montney production.

Lower bitumen sales due to production curtailments at Surmont.

Earnings were positively impacted by:

Increased Montney production from Pad 1 & 2 wells online and partial

year production from the Kelt

acquisition completed in August of 2020.

Total average production increased 7 MBOED in 2020 compared with 2019.

Canada operations reported

earnings of $458 million in 2021 compared with a loss of $326 million in 2020.

Earnings were positively impacted

Higher realized bitumen prices and crude

After-tax gains

on disposition related to contingent

payments of $246 million in 2021 associated

sale of certain assets to CVE in 2017.

Higher sales volumes in our Surmont and Montney

Earnings were negatively impacted

Higher production and operating expenses

primarily due to increased Surmont and Montney

average production

increased 24 MBOED in 2021 compared with 2020.

The production increase was

primarily due to:

Increased liquids and natural gas production from Montney Pad 1 & 2 wells online

and partial year

production from the Kelt acquisition completed in August of 2020.

Decreased mandated production curtailments imposed by the Alberta government.

The production increase was partly offset by:

Lower bitumen production,

primarily due to voluntary curtailments at Surmont in response to the low price

environment of 12 MBOED.

Improved well performance in

New wells online in Montney.

Production from our Kelt acquisition

completed in the third quarter of 2020.

Absence of curtailments.

Results of Operations

ConocoPhillips

Europe, Middle East and North Africa

Net Income Attributable to ConocoPhillips

(millions of dollars)

Net Income (Loss) Attributable

to ConocoPhillips

Consolidated Operations

8 unchanged sentences

Natural gas ($ per mcf)

*Prior periods have been updated to reflect the Middle East Business Unit

moving from Asia Pacific to the Europe, Middle East and North Africa

See Note 24—Segment Disclosures and Related Information in the Notes

to Consolidated Financial Statements for additional

Middle East and North Africa segment consists

of operations principally located in the Norwegian

The Europe, Middle East and North Africa

segment consists of operations

principally located in the Norwegian

sector of the North Sea;

the Norwegian Sea;

and commercial and terminalling

operations in the

In 2020, our Europe, Middle East and North

Africa operations contributed 13 percent of our consolidated

liquids production and 20 percent of our consolidated

and terminalling operations in the U.K.

Europe, Middle East and North Africa

operations contributed

12 percent of our consolidated liquids

and 14 percent of our consolidated

natural gas production.

Net Income Attributable to ConocoPhillips

Earnings for Europe,

Middle East and North Africa operations

of $448 million decreased $2,722 million in

2020 compared with 2019.

The decrease in earnings was primarily

The absence of a $2.1 billion after-tax gain associated

with the completion of the sale of two

ConocoPhillips U.K.

subsidiaries.

For additional information, see Note 4—Asset

Acquisitions and

Dispositions in the Notes to Consolidated Financial

Lower equity in earnings of affiliates, primarily due to

lower LNG sales prices.

Lower realized crude oil prices in Norway.

In the fourth quarter of 2020, the effective tax rate within

our equity method investment in the Europe, Middle

East and North Africa segment increased.

The Europe, Middle East and North Africa

segment reported earnings of $1,167 million in 2021 compared

earnings of $448 million in 2020.

Earnings were positively impacted

Higher realized natural

gas, crude oil and NGL prices.

Higher LNG sales prices, reflected in equity in earnings

of affiliates.

Higher sales volumes of crude oil and LNG.

Earnings were negatively

Higher taxes.

Higher DD&A expenses and production and

operating expenses.

Partly offsetting the increase

expenses were lower rates

from positive reserve revisions.

Consolidated Production

Average consolidated production decreased 88 MBOED in 2020, compared with 2019.

The decrease was

mainly due to:

The absence of production related to our U.K.

disposition in the third quarter of 2019.

Lower volumes from Libya due to a cessation of

production following a period of civil unrest.

Average consolidated

production increased 39 MBOED in 2021, compared

The consolidated production

increase was primarily due to:

Higher production in Libya due to the absence

of a forced shutdown of the Es Sider export

other eastern export terminals.

Improved well performance in

New production from Norway

drilling activities, including our Tor

II redevelopment project which

achieved full production in 2021.

These production increases were partly

Normal field decline.

These production decreases were partly offset by:

New wells online in Norway.

Net Income Attributable to ConocoPhillips

(millions of dollars)

Results of Operations

ConocoPhillips

Net Income (Loss) Attributable

to ConocoPhillips

Consolidated Operations

8 unchanged sentences

Natural gas ($ per mcf)

*Prior periods have been updated to reflect the Middle East Business Unit

moving from Asia Pacific to the Europe, Middle East and North Africa

See Note 24—Segment Disclosures and Related Information in the Notes

to Consolidated Financial Statements for additional

The Asia Pacific segment has operations in China,

Indonesia, Malaysia and Australia.

contributed 10 percent of our consolidated liquids

production and 32 percent of our consolidated

The Asia Pacific segment has operations

in China, Indonesia, Malaysia and Australia.

During 2021, Asia Pacific

contributed 6 percent of our consolidated

liquids production and 17 percent of our consolidated

Net Income Attributable to ConocoPhillips

1 unchanged sentence

in 2021, compared with $962 million in 2020.

The decrease in

earnings was mainly due to:

Lower sales volumes, primarily from lower LNG

sales due to the Australia-West divestiture;

crude oil sales volumes in Malaysia, primarily

due to production curtailments;

and lower crude

volumes in China due to the expiration of the Panyu

production license.

For more information related to

our Australia-West divestiture, see Note 4—Asset Acquisitions and Dispositions in the

Consolidated Financial Statements.

Lower realized commodity prices.

Lower equity in earnings of affiliates from APLNG, mainly

due to lower LNG sales prices.

The absence of a $164 million income tax benefit

related to deepwater incentive tax credits

Malaysia Block G.

Earnings were positively impacted by:

A $597 million after-tax gain on disposition related

to our Australia-West divestiture.

The decrease in earnings

was mainly due to:

An impairment of $688 million after-tax on

our APLNG investment.

Absence of a $597 million after-tax gain

related to our Australia

-West divestiture.

Absence of sales volumes associated with Australia

Earnings were positively impacted

Higher crude oil and natural gas

Higher LNG sales prices, reflected in equity in earnings

of affiliates.

An after-tax gain of $194 million

recognized for a FID bonus associated

with our Australia-West

For additional information related

to this FID bonus, see

Consolidated Production

Average consolidated production decreased 28 percent in 2020, compared with 2019.

The decrease was

primarily due to:

The divestiture of our Australia-West assets.

Average consolidated

production decreased 16 MBOED in 2021, compared

The decrease was primarily

The divestiture of our Australia

-West assets that contributed

18 MBOED in 2020.

Normal field decline.

Higher unplanned downtime due to the rupture

of a third-party pipeline impacting gas production from

the Kebabangan Field in Malaysia.

The expiration of the Panyu production license in

Production curtailments of 4 MBOED in Malaysia.

These production decreases were partly offset by:

Development activity at Bohai Bay in China and

Gumusut in Malaysia.

These production decreases were partly

Development activity at Bohai Bay

First production in Malikai

Phase 2 and SNP Phase 2.

The absence of curtailments across the segment

and increased demand in Indonesia from coal supply

restrictions.

Results of Operations

ConocoPhillips

Other International

Net Income (Loss) Attributable to ConocoPhillips

(millions of dollars)

Net Income (Loss) Attributable

to ConocoPhillips

The Other International segment includes exploration

activities in Colombia and Argentina and contingencies

associated with prior operations in other countries.

As a result of our completed Concho acquisition

January 15, 2021, we refocused our exploration

program and announced our intent to pursue a managed

and appraisal activities in Colombia as well as contingencies

associated with prior operations

in other countries.

As a result of our Concho acquisition, we refocused

exploration program

and announced our intent to pursue

managed exits

from certain areas.

Other International operations reported a loss of $64

million in 2020,

compared with earnings of $263 million

The decrease in earnings was primarily due

The absence of $317 million after-tax in other

income from a settlement award with PDVSA

associated with prior operations in Venezuela.

For additional information related to this settlement

award, see Note 12—Contingencies and Commitments,

in the Notes to Consolidated Financial

Increased exploration expenses, primarily

due to dry hole costs and a full impairment of

undeveloped leasehold costs in Colombia.

Other International operations

reported a loss of $107 million in 2021, compared with a

loss of $64 million in 2020.

Earnings were negatively

A $137 million after-tax loss on divestiture

related to our Argentina

exploration interests.

Absence of a $29 million after-tax benefit to earnings

from the dismissal of arbitration

related to prior

operations in Senegal recognized

in the first quarter of 2020.

Changes to earnings were positively impacted

Absence of exploration expenses

associated with dry hole costs and a full impairment of

undeveloped leasehold costs in Colombia in the fourth

quarter of 2020.

Corporate and Other

Millions of Dollars

Net Income (Loss) Attributable to ConocoPhillips

Corporate general and administrative expenses

Net interest consists of interest and financing expense,

net of interest income and capitalized interest.

interest expense increased $58 million in 2020 compared

primarily due to lower interest income

related to lower cash and cash equivalent balances

Corporate G&A expenses include compensation

programs and staff costs.

These costs decreased by $52

million in 2020 compared with 2019, primarily

due to mark to market adjustments associated

compensation programs.

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

Net Income (Loss) Attributable

to ConocoPhillips

Corporate general and administrative

Net interest consists

of interest and financing expense,

net of interest income and capitalized

interest expense increased $139

million in 2021 compared with 2020, primarily due to higher

debt balances

assumed due to our Concho acquisition.

Corporate G&A expenses include

compensation programs and

These expenses increased by $117

million in 2021 compared with 2020, primarily due to restructuring

expenses associated with our Concho

acquisition and 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

Earnings from Technology

increased by $51 million in 2021 compared with 2020,

primarily due to higher

licensing revenues.

Activities are focused on both conventional and tight

oil reservoirs, shale gas, heavy oil, oil

sands, enhanced

oil recovery and LNG.

Earnings from Technology decreased by $149 million in 2020 compared with 2019,

primarily due to lower licensing revenues.

The category “Other” includes certain foreign currency

transaction gains and losses, environmental costs

associated with sites no longer in operation, other

costs not directly associated with an operating

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.

Earnings in “Other” decreased by $1,763 million

in 2020 compared with 2019,

primarily due to:

An unrealized loss of $855 million after-tax

on our CVE common shares in 2020,

compared with a

$649 million after-tax unrealized gain in 2019.

The absence of a $151 million tax benefit related

to the revaluation of deferred tax assets

finalization of rules related to the 2017 Tax Cuts and Jobs Act.

See Note 18—Income Taxes, in the

Notes to Consolidated Financial Statements,

for additional information related to the 2017 Tax Cuts

and Jobs Act.

holding gains or losses on equity securities, and

settlement expense.

Earnings in “Other” increased by $1,875 million in 2021 compared

with 2020, primarily due

to a gain of $1,040 million on our CVE common shares

in 2021, compared with a $855 million loss in 2020.

Capital Resources and Liquidity

ConocoPhillips

Capital Resources and Liquidity

Financial Indicators

1 unchanged sentence

Except as Indicated

Net cash provided by operating activities

Net cash provided by operating

Cash and cash equivalents

1 unchanged sentence

Short-term debt

Percent of total debt to capital*

Percent of floating-rate debt to total debt

Percent of total debt to

Percent of floating-rate

debt to total debt

*Capital includes total debt and total equity.

To meet our short-

and long-term liquidity requirements, we look

to a variety of funding sources, including

cash generated from operating activities,

proceeds from asset sales, our commercial paper

and credit facility

programs and our ability to sell securities

using our shelf registration statement.

In 2020, the primary uses of

our available cash were $4,715 million to support

our ongoing capital expenditures and investments

$1,831 million to pay dividends on our common

$892 million to repurchase our common

$658 million for net purchase of investments.

During 2020, cash and cash equivalents decreased

million to $2,991 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

in available liquidity.

This strong foundation allowed us to be measured

in our response to the sudden change

in business environment as we exited the first

quarter of 2020.

In response to the oil market downturn

began in early 2020,

we announced the following capital, share repurchase

and operating cost reductions.

reduced our 2020 operating plan capital expenditures

by a total of $2.3 billion, or approximately

percent of the original guidance.

We suspended our share repurchase program, further reducing cash outlays

by approximately $2 billion.

We also reduced our operating costs by approximately $0.6 billion,

ten percent of the original 2020 guidance.

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

approximately $5 billion versus the original operating

Considering the weakness in oil prices during the

second quarter of 2020, we established a framework

evaluating and implementing economic curtailments,

which resulted in taking an additional significant

curtailing production, predominantly from

operated North American assets.

Due to our strong balance sheet,

we were in an advantaged position to forgo some production

and cash flow in anticipation of receiving higher

cash flows for those volumes in the future.

Based on our economic criteria, we began

restoring production

from voluntary curtailments in July, and with oil prices stabilizing around $40 per

barrel, we ended our

curtailment program by the end of the third quarter.

In the fourth quarter of 2020, we resumed

share repurchases, repurchasing $0.2 billion

of shares in October,

before suspending our share repurchase program

upon entry into a definitive agreement to

acquire Concho.

We resumed share repurchases in February 2021 after completion of our Concho

As of December 31, 2020,

we had cash and cash equivalents of $3.0 billion,

short-term investments of $3.6

billion, and available borrowing capacity under

our credit facility of $5.7 billion, totaling

over $12 billion of

We believe current cash balances and cash generated by operations, together with access to external

sources of funds as described below in the “Significant

Changes in Capital” section, will be sufficient

our funding requirements in the near- and long-term, including

our capital spending program, dividend

payments and required debt payments.

and long-term liquidity requirements,

we look to a variety of funding sources,

including cash

generated from operating

activities, proceeds from asset sales,

our commercial paper and credit facility programs

and our ability to sell securities using our shelf registration

In 2021, the primary uses of our available

cash were $8.7 billion for the acquisition

of Shell Permian;

$5.3 billion to support our ongoing capital expenditures

and investments program;

$3.6 billion to repurchase our common stock;

$2.4 billion to pay dividends;

billion for hedging, transaction and restructuring

In 2021, cash and cash equivalents increased by

billion to $5.0 billion.

At December 31, 2021, we had cash and cash

equivalents of $5.0 billion, short-term investments

of $0.4 billion,

and available borrowing capacity

under our credit facility of $6.0 billion, totaling

approximately $11.5 billion

We believe current cash

balances and cash generated by

operations, together with access to

sources of funds as described below in the “Significant Changes

in 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 Changes in Capital

Operating Activities

During 2020, cash provided by operating activities

was $4,802 million, a 57 percent decrease from 2019.

decrease was primarily due to lower realized

commodity prices, normal field decline,

production curtailments,

the divestiture of our U.K.

and Australia-West assets, and the absence in 2020 of collections under our

settlement agreement with PDVSA,

partially offset by lower production and operating

and long-term operating cash flows are highly

dependent upon prices for crude oil, bitumen, natural

In 2021, cash provided by operating

activities was $17 billion, compared with $4.8 billion

The increase is

primarily due to higher realized commodity

prices and higher sales volumes,

mostly resulting from our acquisition

The increase was partly offset by

the $0.8 billion in settlement of oil and gas hedging

acquired from Concho, and approximately

$0.4 billion of transaction and restructuring

and long-term operating cash flows

are highly dependent upon prices for crude oil, bitumen,

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.

year production averaged 1,127 MBOED in 2020.

Full-year production excluding Libya averaged

been volatile and are driven by market

conditions over which we have no

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

production averaged

1,567 MBOED in 2021.

Adjusting for estimated curtailments of approximately

closed acquisitions and

dispositions;

and excluding Libya;

production for 2020 was 1,176 MBOED.

Production in 2021 is expected to

be approximately 1.5 MMBOED, reflecting the

impact from the Concho acquisition.

Full-year production excluding

Libya averaged 1,527

Adjusting for closed acquisitions and dispositions,

impacts from 2020 curtailments, 2021 Winter Storm

conversion of Concho two-stream

contracted volumes to a

three-stream basis, production

increased 28 MBOED or

First quarter 2022 production

is expected to be 1.75 MMBOED to 1.79 MMBOED.

Future production is

subject to numerous uncertainties, including,

among others, the volatile crude oil and

natural gas price

environment, which may impact investment decisions;

the effects of price changes on production sharing

among others, the volatile crude oil and natural

environment, which may impact

investment decisions;

of price changes on production sharing and

variable-royalty contracts;

acquisition and disposition

acquisition and disposition of fields;

field production decline rates;

technologies;

new technologies;

operating efficiencies;

2 unchanged sentences

political instability;

related disruptions;

and the addition of proved

reserves through exploratory success and

their timely and cost-

effective development.

weather-related disruptions;

Capital Resources and Liquidity

ConocoPhillips

and the addition of proved reserves through

exploratory success and their timely and cost

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

To maintain or grow our production volumes on an ongoing basis, we must continue

to add to our proved

reserve base.

Our proved reserves generally increase as prices

rise and decrease as prices decline.

replacement represents the net change in proved

production levels can cause variability

in cash flows,

although generally this variability has

not been as significant as that caused by commodity prices.

or grow our production volumes on

an ongoing basis, we must continue to add

to our proved reserve

Our proved reserves generally

increase as prices rise and decrease as prices decline.

Reserve replacement

represents the net change in proved

reserves, net of production, divided by our current

production, as shown in our supplemental reserve table

Our reserve replacement was negative 86

percent in 2020, reflecting the impact of lower

prices, which reduced reserves by approximately

Our organic reserve replacement, which excluded a net

decrease of 7 MMBOE from sales and purchases,

negative 84 percent in 2020.

In the three years ended December 31, 2020, our reserve

replacement was 59 percent, reflecting the impact

lower prices in 2020.

Our organic reserve replacement during the three years

ended December 31, 2020,

which excluded a net increase of 89 MMBOE related

to sales and purchases, was 53 percent.

For additional information about our 2021 capital

budget, see the “2021 Capital Budget” section

“Capital Resources and Liquidity” and for additional

information on proved reserves, including both

developed and undeveloped reserves, see the “Oil

and Gas Operations” section of this report.

year production.

information on proved

reserves, including both developed and undeveloped

see the reserve table

disclosures contained in “Supplementary Data – Oil and Gas Operations.”

See “Item 1A—Risk Factors – Unless we

successfully develop our resources, the scope of our business will decline, resulting in an adverse impact to our

As discussed in the “Critical Accounting Estimates”

section, engineering estimates of proved

therefore, each year reserves may be revised

upward or downward due to the impact of changes

commodity prices or as more technical data becomes

available on reservoirs.

It is not possible to reliably

predict how revisions will impact reserve quantities

in the future.

therefore, reserves

may be revised upward or

downward each year due to the impact of changes

commodity prices or as more technical data

becomes available on reservoirs.

It is not possible to reliably predict

how revisions will impact future reserve quantities.

Investing Activities

In 2020, we invested $4.7 billion in capital

expenditures, of which $0.5 billion consisted of

acquisitions, including additional Montney acreage.

Capital expenditures invested in 2019 and 2018

billion and $6.8 billion,

respectively.

For information about our capital expenditures

and investments, see the

In 2021, we invested $5.3 billion

in capital expenditures.

Capital expenditures invested

in 2020 and 2019 were

$4.7 billion and $6.6 billion, respectively.

For information about our

capital expenditures and investments,

We invest in short-term investments as part of our cash investment strategy, the primary objective of which is

to protect principal, maintain liquidity and provide

yield and total returns;

these investments include time

deposits, commercial paper as well as debt securities

classified as available for sale.

Funds for short-term

needs to support our operating plan and provide resiliency

to react to short-term price volatility are invested

highly liquid instruments with maturities within

Funds we consider available to maintain resiliency

in longer term price downturns and to capture

opportunities outside a given operating

plan may be invested in

instruments with maturities greater than one year.

For additional information, see Note 1–Accounting

and Note 13–Derivative and Financial Instruments,

in the Notes to Consolidated Financial

Investing activities in 2020 included net purchases

of $658 million of investments,

of which $420 million was

invested in short-term instruments and $238 million

was invested in long-term instruments.

activities in 2019 included net purchases of $2.9

billion of investments,

of which $2.8 billion was invested in

short-term instruments and $0.1 billion was invested

in long-term instruments.

For additional information, see

Note 13—Derivative and Financial Instruments,

in the Notes to Consolidated Financial

Proceeds from asset sales in 2020 were $1.3 billion.

We received cash proceeds of $765 million for the

divestiture of our Australia-West assets and operations,

with another $200 million payment due upon final

investment decision of the proposed Barossa

development project.

We also received proceeds of $359 million

and $184 million for the sale of our Niobrara interests

and Waddell Ranch interests in the Lower 48,

respectively.

Proceeds from asset sales in 2019 were $3.0 billion,

including $2.2 billion for the sale of

two ConocoPhillips

subsidiaries and $350 million for

the sale of our 30 percent interest in the Greater

“Capital Expenditures and Investments”

In December 2021, we completed our acquisition

of Shell’s assets in

the Delaware Basin for cash consideration

approximately $8.7 billion after

customary adjustments.

We funded this transaction with cash

completed our acquisition of Concho on January 15, 2021.

The assets acquired in the transaction included

million of cash.

The net impact of these items is recognized

within “Acquisition

of businesses, net of cash

acquired” on our consolidated sta

tement of cash flows.

In 2021, we announced a disposition target

of $4 to $5 billion in disposition proceeds by year-end

proceeds from transactions announced

or initiated in the third quarter of 2021 or later

will be counted toward this

The proceeds from these transactions

will be used in accordance with the company’s

priorities, including

returns of capital to shareholders

and reduction of gross debt.

we have achieved $0.3 billion from

sale of noncore assets in our Lower 48 segment.

proceeds from asset dispositions

in 2021 were $1.7 billion.

Including the $250 million mentioned above, we

also received cash proceeds of $1.14 billion from

sales of our investment in CVE

common shares and $244 million

of contingent payments related

to dispositions completed before

In May 2021, we announced

and began a paced monetization of our

investment in CVE with the plan to

direct proceeds toward

share repurchase program.

We expect to fully dispose

of our CVE common shares by early 2022, however,

sales pace will be guided by market conditions,

and we retain discretion to

adjust accordingly.

Proceeds from asset sales in 2020 were $1.3

We received cash

proceeds of $765 million for the divestiture

of our Australia-West

assets and operations.

We also received proceeds of $359

million and $184 million from the

sale of our Niobrara interests

and Waddell Ranch interests

in the Lower 48, respectively.

Proceeds from asset sales in 2019 were $3.0

billion, including $2.2 billion for the sale of two ConocoPhillips

subsidiaries and $350 million for the sale of our 30 percent

interest in the Greater

Sunrise Fields.

Proceeds from assets sales in 2018 were $1.1

billion, including several non-core assets in

the Lower 48, as

well as the sale of a ConocoPhillips subsidiary

which held 16.5 percent of our 24 percent interest

Field in the U.K.

For additional information on our dispositions,

see Note 4—Asset Acquisitions and

Dispositions in the Notes to Consolidated Financial

We invest in short

-term investments as part of our

cash investment strategy,

the primary objective of which is to

protect principal, maintain liquidity

and provide yield and total returns;

these investments include time deposits,

commercial paper,

as well as debt securities classified as available

Funds for short-term needs

our operating plan and provide resiliency

to react to short-term price volatility

are invested in highly liquid

instruments with maturities within the year.

Funds we consider available to maintain

resiliency in longer term

Capital Resources and Liquidity

ConocoPhillips

price downturns and to capture opportunities

outside a given operating plan may

be invested in instruments

maturities greater than one year.

Financing Activities

We have a revolving credit facility totaling $6.0 billion, expiring in May 2023.

We have a revolving

credit facility totaling $6.0 billion, expiring

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

maintenance of specified financial ratios or credit

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 U.S.

The agreement calls for commitment fees

on available, but unused,

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’s ability to issue up to $6.0 billion of

commercial paper, which is primarily a funding source for short-term

working capital needs.

paper maturities are generally limited to 90 days.

With $300 million of commercial paper outstanding and no

direct borrowings or letters of credit,

we had $5.7 billion in available borrowing capacity

under the revolving

credit facility at December 31, 2020.

We may consider issuing additional commercial paper in the future to

supplement our cash position.

In October 2020, Moody’s affirmed its rating of our senior long-term debt of “A3”

with a “stable” outlook, and

affirmed its rating of our short-term debt as “Prime-2.”

In January 2021, Fitch affirmed its rating of our long-

term debt as “A” with a “stable” outlook and affirmed its

rating of our short-term debt as “F1+.”

25, 2021, S&P revised the industry risk assessment

for the E&P industry to ‘Moderately High’ from

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

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 the redetermination

prior to its expiration

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 U.S.

The agreement calls for commitment

fees on available, but unused,

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

ConocoPhillips Company’s ability to

issue up to $6.0 billion of commercial

is primarily a funding source for short-term working

capital needs.

Commercial paper maturities are

generally limited to 90 days.

With no commercial paper outstanding

and no direct borrowings or letters

we had access to $6.0 billion in available borrowing

capacity under the revolving credit facility

at December 31,

On January 15, 2021, we completed the acquisition of Concho

in an all-stock transaction.

In the acquisition,

assumed Concho’s publicly

traded debt and in December 2020, we launched an offer

to exchange Concho’s

publicly traded debt for debt issued

by ConocoPhillips.

There were no impacts to ConocoPhillips’

credit ratings as a

result of the debt exchange.

In June 2021, we reaffirmed our

commitment to preserving our ‘A’

-rated balance

sheet by restating our intent

to reduce gross debt by $5 billion over

the next five years, driving a more resilient

efficient capital structure.

On January 25, 2021, S&P revised the industry risk assessment

for the E&P industry to ‘Moderately

‘Intermediate’ based on a view of increasing

risks from the energy transition, price volatility, and weaker

risks from the energy transition,

price volatility,

profitability.

On February 11, 2021, S&P downgraded its rating of our long-term debt

from “A” to “A-” with a

“stable” outlook and downgraded its rating of our short-term

debt from “A-1” to “A-2.”

On February 11, 2021, S&P downgraded its rating

of our long-term debt from “A”

“stable” outlook and affirmed

this rating in November 2021.

In October 2021, Moody’s affirmed its “A3”

our long-term debt and revised its outlook

from “stable” to “positive”.

In December 2021, Fitch affirmed its rating

of our long-term debt as “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, upon downgrade of our credit ratings.

If our credit ratings

are downgraded from their

current levels, it could increase the cost of corporate

debt available to us and restrict our access to

ratings triggers on any of our corporate

debt that would cause an automatic default,

thereby impact our access to liquidity,

upon downgrade of our credit ratings.

If our credit ratings are downgraded

from their current levels, it could

increase the cost of corporate

debt available to us and restrict

our access to the

commercial paper markets.

If our credit rating were to deteriorate

to a level prohibiting us from accessing the

commercial paper market, we would still

be able to access funds under our revolving credit

Certain of our project-related contracts, commercial

contracts and derivative instruments contain

to a level prohibiting us from accessing

commercial paper market, we

would still be able to access funds under our revolving

credit facility.

Certain of our project-related

contracts, commercial contracts

and derivative instruments contain

requiring us to post collateral.

Many of these contracts and instruments permit

us to post either cash or letters

of credit as collateral.

Many of these contracts and instruments

permit us to post either cash or letters

credit as collateral.

At December 31, 2021 and 2020, we had direct

bank letters of credit of $249 million

and $277 million, respectively, which secured performance obligations related to

various purchase

commitments incident to the ordinary conduct of

In the event of credit

ratings downgrades, we may

be required to post additional letters of

On January 15, 2021, we completed the acquisition

of Concho in an all-stock transaction.

In the acquisition,

we assumed Concho’s publicly traded debt.

On December 7, 2020, we launched an offer to exchange

Concho’s publicly traded debt for debt issued by ConocoPhillips.

The exchange offer settled on February 8,

Of the approximately $3.9 billion in aggregate

principal amount of Concho’s notes subject to the

exchange offer, 98 percent, or approximately $3.8 billion, was tendered and

exchanged for new debt issued by

bank letters of credit of $337 million and

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

letters of credit.

We have a universal

shelf registration statement

on file with the SEC under which we have the

ability to issue and

sell an indeterminate amount of various

types of debt and equity securities.

Capital Resources and Liquidity

ConocoPhillips

There were no impacts to ConocoPhillips’

credit ratings as a result of the debt exchange.

additional information,

see Note 10—Debt and Note 25—Acquisition

of Concho Resources Inc., in the Notes

to Consolidated Financial Statements.

Shelf Registration

We have a universal shelf registration statement on file with the SEC under which

we have the ability to issue

and sell an indeterminate amount of various types

of debt and equity securities.

Guarantor Summarized Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company

and Burlington Resources

LLC, with respect to publicly held debt securities.

ConocoPhillips Company is 100 percent

Capital Requirements

For information about our capital

expenditures and investments,

see the “Capital Expenditures and Investments”

Our debt balance at December 31, 2021, was $19.9 billion,

an increase of $4.6 billion from the balance at

December 31, 2020, driven by debt acquired as part

of the Concho acquisition.

Maturities of debt (including

payments for finance leases) due in

2022 of $1.1 billion will be paid from current cash

balances and cash generated

by operations.

In December 2021, we announced our expected 2022 return

of capital program and the initiation

of a three-tier

return of capital framework.

The framework is structured

to deliver a compelling, growing ordinary dividend

through-cycle share repurchases.

It includes the addition of a discretionary VROC tier.

The VROC will provide a

flexible tool for meeting our commitment

of returning greater than

30 percent of cash from operating

during periods where commodity prices are meaningfully

higher than our planning price range.

We have set our

expected 2022 total capital returns

at approximately $8 billion,

consisting of distributions from each of the three

Consistent with our commitment to

deliver value to shareholders,

in 2021, we paid $2.4 billion, $1.75 per share of

common stock, in ordinary dividends.

was an increase over 2020 and 2019, when we paid $1.69 and

share of common stock, respectively.

On February 3, 2022, we announced a quarterly dividend of $0.46 per share,

payable March 1, 2022, to stockholders

of record at the close of business on February

On January 14,

2022, we paid the first VROC payment

of $0.20 per share to shareholders

of record as of January 3, 2022.

February 3, 2022, we announced a VROC of $0.30 per share,

payable on April 14, 2022, to stockholders

the close of business on March 31, 2022.

The ordinary dividend and VROC are subject to

numerous considerations

and will be determined and approved

each quarter by the Board of Directors.

We expect to announce the VROC

when we announce our ordinary

dividend, but the quarterly payouts

will be staggered from the ordinary dividend,

resulting in up to eight cash

distributions throughout the year.

In late 2016, we initiated our current

share repurchase program

with Board of Director’s authorization

billion of our common stock.

Share repurchases were $3.6

billion, $0.9 billion, and $3.5 billion in 2021, 2020, and

2019, respectively.

As of December 31, 2021, share repurchases

since the inception of our current program

totaled 247 million shares and $14 billion.

Repurchases are made at management’s

discretion, at prevailing prices,

subject to market conditions and

other factors.

For more information on factors

considered when determining the levels of returns

see “Item 1A—Risk

Factors – Our ability to execute our capital return program is subject to certain considerations.”

In addition to the priorities described above, we have

contractual obligations

to purchase goods and services of

approximately $11.8 billion.

We expect to fulfill $6 billion of these

obligations in 2022.

These figures exclude

purchase commitments for jointly

owned fields and facilities where we are not

the operator.

Purchase obligations

of $5.3 billion are related to agreements

to access and utilize the capacity of third

-party equipment and facilities,

including pipelines and LNG product terminals, to

transport, process, treat and store

obligations of $5.3 billion are related

to market-based contracts

for commodity product purchases

The remainder is primarily our net share of purchase

commitments for materials

and services for jointly

owned fields and facilities where we are the operator.

Capital Resources and Liquidity

ConocoPhillips

Burlington Resources LLC is 100 percent

owned by ConocoPhillips Company.

ConocoPhillips and/or ConocoPhillips Company

have fully and unconditionally guaranteed

obligations of Burlington Resources LLC, with respect

to its publicly held debt securities.

ConocoPhillips has fully and unconditionally

guaranteed the payment obligations of ConocoPhillips

with respect to its publicly held debt securities.

In addition, ConocoPhillips Company

has fully and

unconditionally guaranteed the payment obligations

of ConocoPhillips with respect to its publicly

All guarantees are joint and several.

In March of 2020, the SEC adopted amendments

to simplify the financial disclosure requirements

guarantors and issuers of guaranteed securities

registered under Rule 3-10 of Regulation S-X.

evaluation of our existing guarantee relationships,

we qualify for the transition to alternative disclosures.

elected early voluntary compliance with the final

amendments beginning in the third quarter

Accordingly, condensed consolidating information by guarantor and issuer of

guaranteed securities will no

longer be reported, and alternative disclosures

of summarized financial information for the

Obligor Group is presented.

The following tables present summarized financial

information for the Obligor

Group, as defined below:

The Obligor Group will reflect guarantors and issuers

of guaranteed securities consisting of

ConocoPhillips, ConocoPhillips Company and

Burlington Resources LLC.

Capital Expenditures and Investments

Millions of Dollars

Europe, Middle East and North Africa

Other International

Corporate and Other

Capital Program*

* Excludes capital related to acquisitions of businesses, net of capital acquired.

Our capital expenditures and investments

for the three-year period ended December 31,

2021, totaled

$16.7 billion.

The 2021 expenditures supported

key exploration

and developments, primarily:

Development activities in the Lower 48, primarily Permian,

Eagle Ford, and Bakken.

Appraisal and development activities in Alaska

related to the Western

North Slope and development

activities in the Greater Kuparuk Area.

Appraisal and development activities in the

Montney and optimization of oil sands

development in

Continued development activities across

assets in Norway.

Continued development activities in China,

Malaysia, and Indonesia.

2022 Capital Budget

In December 2021, we announced our 2022 operating plan

capital of $7.2 billion.

The plan includes funding for

ongoing development drilling programs,

major projects, exploration and

appraisal activities, base maintenance and

$0.2 billion for projects to reduce

the company’s scope

1 and 2 emissions intensity and investments

early-stage low-carbon

opportunities that address end-use emissions.

Capital Resources and Liquidity

ConocoPhillips

Guarantor Summarized Financial

We have various

cross guarantees among ConocoPhillips,

ConocoPhillips Company,

and Burlington Resources LLC

with respect to publicly held debt securities.

ConocoPhillips Company is 100 percent

owned by ConocoPhillips.

Burlington Resources LLC is

100 percent owned by ConocoPhillips Company.

ConocoPhillips and/or ConocoPhillips

Company have fully and unconditionally

guaranteed the payment obligations

of Burlington Resources LLC with

respect to its publicly held debt securities.

Similarly, ConocoPhillips

has fully and unconditionally guaranteed the

payment obligations of ConocoPhillips

Company with respect to its publicly held

debt securities.

ConocoPhillips Company has fully and unconditionally

guaranteed the payment obligations

of ConocoPhillips with

respect to its publicly held debt securities.

All guarantees are joint and

The following tables present summarized

financial information for

the Obligor Group, as defined below:

The Obligor Group will reflect guarantors

and issuers of guaranteed securities consisting

ConocoPhillips, ConocoPhillips Company

and Burlington Resources LLC.

Consolidating adjustments for elimination

of investments in and transactions between the collective

guarantors and issuers of guaranteed securities

are reflected in the balances of the summarized

financial information.

Non-Obligated Subsidiaries are excluded

from this presentation.

Transactions and balances reflecting activity between the Obligors

and Non-Obligated Subsidiaries are

presented separately below:

Summarized Income Statement Data

of investments in and transactions

between the collective

guarantors and issuers

of guaranteed securities are reflected

in the balances of the summarized financial

Non-Obligated Subsidiaries are exclud

ed from this presentation.

Upon completing the Concho acquisition on January 15, 2021, we assumed

Concho’s publicly traded

approximately $3.9 billion in aggregate

principal amount, which was recorded

at the fair value of $4.7 billion on

the acquisition date.

We completed a debt exchange

offer that settled

on February 8, 2021, of which 98 percent,

or approximately $3.8 billion in

aggregate principal amount of Concho’s

notes, were tendered and accepted

new debt issued by ConocoPhillips.

The new debt issued in the exchange is fully and

unconditionally guaranteed

by ConocoPhillips Company.

Both the guarantor and issuer of the exchange

debt is reflected within the Obligor

Group presented here.

and balances reflecting activity between the Obligors

and Non-Obligated Subsidiaries

are presented

separately below:

Summarized Income Statement

Millions of Dollars

2 unchanged sentences

Net income (loss)

Net Income (Loss) Attributable to ConocoPhillips

Net Income (Loss) Attributable

to ConocoPhillips

*Includes approximately $5.4 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

Summarized Balance Sheet Data

6 unchanged sentences

Current liabilities

Amounts due to Non-Obligated Subsidiaries, current

Amounts due to Non-Obligated Subsidiaries,

Noncurrent liabilities

Amounts due to Non-Obligated Subsidiaries, noncurrent

Capital Requirements

For information about our capital expenditures

and investments, see the “Capital Expenditures

Our debt balance at December 31, 2020, was $15,369

million, an increase of $474 million from

the balance at

December 31, 2019.

Maturities of debt (including payments for

finance leases) due in 2021 of $601 million,

excluding net unamortized premiums and discounts,

will be paid from current cash balances and cash

generated by operations.

For more information on Debt, see Note 10—Debt,

in the Notes to Consolidated

Financial Statements.

We believe in delivering value to our shareholders via a growing and sustainable dividend

supplemented by

additional returns of capital, including share repurchases.

In 2020, we paid $1,831 million, $1.69 per share of

common stock, in dividends.

This is an increase

over 2019 and 2018, when we paid $1.34 and

$1.16 per share

of common stock, respectively.

In February 2021, we announced a quarterly dividend

of $0.43 per share,

payable March 1, 2021, to stockholders of record

at the close of business on February 12, 2021.

In late 2016, we initiated our current share repurchase

program, which has a current total program

authorization of $25 billion of our common stock.

Cost of share repurchases were $892 million,

million and $2,999 million in 2020, 2019 and

respectively.

Share repurchases since inception of our

current program totaled 189

million shares at a cost of $10,517 million, as of

December 31, 2020.

fourth quarter of 2020, we suspended share repurchases

upon entry into a definitive agreement

We resumed share repurchases in February 2021 after the completion of our Concho acquisition.

Repurchases are made at management’s discretion, at prevailing prices,

subject to market conditions and other

Our dividend and share repurchase programs are

subject to numerous considerations, including

conditions, management discretion and other factors.

See “Item 1A—Risk Factors

Our ability to declare and

pay dividends and repurchase shares is subject to

certain considerations.”

In addition to the requirements above, we have contractual

obligations for the purchase of goods and services

of approximately $8,123 million.

We expect to fulfill $2,805 million of these obligations in 2021.

figures exclude purchase commitments

for jointly owned fields and facilities where

we are not the operator.

Purchase obligations of $5,237 million

are related to agreements to access and utilize

the capacity of third-

party equipment and facilities, including pipelines

and LNG product terminals, to transport, process,

store commodities.

Purchase obligations of $2,290 million are related

to market-based contracts for

commodity product purchases with third parties.

The remainder is primarily our net share

commitments for materials and services for jointly

owned fields and facilities where we are the operator.

Capital Expenditures and Investments

Millions of Dollars

Europe, Middle East and North Africa

Other International

Corporate and Other

Capital Program

Our capital expenditures and investments

for the three-year period ended December 31,

2020 totaled $18.1

The 2020 expenditures supported key exploration

and developments, primarily:

Development and appraisal in the Lower 48, including

Eagle Ford, Permian, and Bakken.

Appraisal and development activities

in Alaska related to the Western North Slope;

activities in the Greater Kuparuk Area and

the Greater Prudhoe Area.

Development and exploration activities

across assets in Norway.

Appraisal activities in liquids-rich plays and optimization

of oil sands development in Canada.

Continued development activities in China, Malaysia,

and Indonesia.

Exploration activities in Argentina.

2021 CAPITAL BUDGET

In February 2021, we announced 2021 operating

plan capital for the combined company of $5.5

plan includes $5.1 billion to sustain current

production and $0.4 billion for investment

in major projects,

primarily in Alaska, in addition to ongoing exploration

appraisal activity.

The operating plan capital budget of $5.5 billion

is expected to deliver production from the combined

of approximately 1.5 MMBOED in 2021.

This production guidance excludes Libya.

For information on PUDs and the associated costs

to develop these reserves, see the “Oil and Gas

section in this report.

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

Amounts due to Non-Obligated Subsidiaries,

Capital Resources and Liquidity

ConocoPhillips

Contingencies

In the case of all known contingencies (other

than those related to income taxes), we accrue

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,

end of the range is accrued.

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

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

With respect to income

tax-related contingencies, we use a cumulative probability-weighted

loss accrual in cases where sustaining a

tax position is less than certain.

Based on currently available information, we believe

it is remote that future costs related to known

liability exposures will exceed current accruals by

an amount that would have a material

adverse impact on our

consolidated financial statements.

For information on other contingencies, see

“Critical Accounting

Estimates” and 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

We are subject to legal proceedings,

claims, and liabilities that arise in the ordinary course of business.

for losses associated with legal

claims when such losses are considered probable

and the amounts can be

reasonably estimated.

See “Critical Accounting Estimates”

for information on contingencies.

Legal and Tax

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.

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

relate to alleged

royalty and tax underpayments

on certain federal, state

and privately owned properties,

claims of alleged

environmental contamination

and damages from historic operations,

and climate change.

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

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

adequacy of current accruals and determines if

adjustment of existing accruals, or establishment

accruals, is required.

See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements,

additional information about income tax-related

contingencies.

Our process facilitates the

early evaluation and quantification

of potential exposures in individual cases.

process also enables us to track those cases

that have been scheduled for trial and/or

professional judgment and experience

in using these litigation management

tools and available information

current developments in all our cases,

our legal organization regularly

assesses the adequacy of current accruals

and determines if an adjustment of existing

accruals, or establishment of new accruals, is

Environmental

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

We are subject to the same numerous

international, federal,

state, and local environmental

laws and regulations

5 unchanged sentences

air emissions.

Federal Clean Water Act, which governs discharges to water bodies.

European Union Regulation for Registration, Evaluation,

Federal Clean Water

Act, which governs discharges

to water bodies.

European Union Regulation for

Registration, Evaluation,

Authorization and Restriction of Chemicals

Federal Comprehensive Environmental

Response, Compensation and Liability Act

Federal Comprehensive

Environmental Response,

Compensation and Liability Act (CERCLA or

Superfund), which imposes liability on generators,

transporters and arrangers of hazardous substances

at sites where hazardous substance releases have

occurred or are threatening to occur.

Federal Resource Conservation and Recovery

transporters and arrangers

of hazardous substances at

sites where hazardous substance

releases have occurred or are

threatening to occur.

Federal Resource

Conservation and Recovery

Act (RCRA), which governs the treatment,

and disposal of solid waste.

Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators

facilities and pipelines, lessees or permittees

of an area in which an offshore facility is located, and

owners and operators of vessels are liable for

removal costs and damages that result from

of oil into navigable waters of the U.S.

Federal Emergency Planning and Community Right-to-Know

Act (EPCRA), which requires

facilities to report toxic chemical inventories

with local emergency planning committees and response

Federal Safe Drinking Water Act, which governs the disposal of wastewater

in underground

injection wells.

disposal of solid waste.

Federal Oil Pollution Act

of 1990 (OPA90), under which

owners and operators

of onshore facilities

and pipelines, lessees or permittees of an area in which an

offshore facility is located,

and owners and

operators of vessels

are liable for removal costs

and damages that result from a discharge

navigable waters

Federal Emergency Planning

and Community Right-to-Know Act (EPCRA),

which requires facilities to

report toxic chemical inventories

with local emergency planning committees

and response departments.

Federal Safe Drinking

Water Act, which governs

the disposal of wastewater

in underground injection

Department of the Interior regulations,

which relate to offshore oil and gas operations in U.S.

waters and impose liability for the cost of pollution

cleanup resulting from operations, as well as

potential liability for pollution damages.

European Union Trading Directive resulting in European

which relate to offshore oil and

gas operations in U.S.

and impose liability for the cost of pollution

cleanup resulting from operations, as

well as potential liability

for pollution damages.

European Union Trading

Directive resulting in European

Emissions Trading Scheme.

Capital Resources and Liquidity

ConocoPhillips

These laws and their implementing regulations

set limits on emissions and, in the case of discharges to

establish water quality limits and establish standards

and impose obligations for the remediation

of releases of

hazardous substances and hazardous wastes.

They also, in most cases, require permits in

association with new

or modified operations.

These permits can require an applicant to

collect substantial information in connection

with the application process, which can be expensive

set limits on emissions and, in the case of discharges

establish water quality limits, and

establish standards and impose obligations

for the remediation of releases of

hazardous substances

and hazardous wastes.

They also, in most cases, require permits

in association with new or

modified operations.

These permits can require an applicant

to collect substantial information

in connection with

the application process, which can be expensive

and time-consuming.

In addition, there can be delays

associated with notice and comment periods and

the agency’s processing of the application.

delays associated with the permitting process

are beyond the control of the applicant.

Many states and foreign countries where

we operate also have, or are developing, similar

In addition, there can be delays associated

with notice and comment periods and the agency’s

processing of the application.

Many of the delays associated

with the permitting process are beyond

the control of the applicant.

Many states and foreign

countries where we operate

also have or are developing, similar environmental

regulations governing these same types of activities.

While similar,

in some cases these regulations may impose

additional, or more stringent, requirements

that can add to the cost and difficulty

of marketing or transporting

products across state

and international borders.

The ultimate financial impact arising from environmental

laws and regulations is neither clearly known

determinable as new standards,

such as air emission standards and water

quality standards, continue to

environmental laws

and regulations governing these same types of

While similar, in some cases these regulations may

impose additional, or more stringent, requirements

that can add to the cost and difficulty of marketing

transporting products across state and international

The ultimate financial impact arising from

environmental laws and regulations is neither

clearly known nor

easily determinable as new standards, such as

air emission standards and water quality standards,

However, environmental laws and regulations, including those that

may arise to address concerns

about global climate change, are expected to continue

to have an increasing impact on our operations

and in other countries in which we operate.

Notable areas of potential impacts include air emission

compliance and remediation obligations in

An example is the use of hydraulic fracturing,

an essential completion technique that facilitates

production of

oil and natural gas otherwise trapped in lower

permeability rock formations.

A range of local, state, federal or

national laws and regulations currently govern

hydraulic fracturing operations, with hydraulic

currently prohibited in some jurisdictions.

Although hydraulic fracturing has been conducted

decades, a number of new laws, regulations

and permitting requirements are under consideration

state environmental agencies, and others which

could result in increased costs, operating restrictions,

operational delays and/or limit the ability

to develop oil and natural gas resources.

Governmental restrictions

on hydraulic fracturing could impact the overall

profitability or viability of certain of our oil

and natural gas

We have adopted operating principles that incorporate established industry standards

meet or exceed government requirements.

Our practices continually evolve as technology

regulations change.

We also are subject to certain laws and regulations relating to environmental remediation

associated with current and past operations.

Such laws and regulations include CERCLA

and RCRA and their

state equivalents.

Longer-term expenditures are subject to considerable

uncertainty and may fluctuate

significantly.

We occasionally receive requests for information or notices of potential liability

from the EPA and state

environmental agencies alleging we are a potentially

responsible party under CERCLA or an equivalent

On occasion, we also have been made a party

to cost recovery litigation by those agencies

private parties.

These requests, notices and lawsuits assert

potential liability for remediation costs at various

sites that typically are not owned by us, but allegedly

contain wastes attributable to our past operations.

and regulations, including those that may

arise to address concerns about global

climate change, are expected

to continue to have an

increasing impact on our operations in the U.S.

countries in which we operate.

Notable areas of potential impacts include

air emission compliance and

remediation obligations in the U.S.

An example is the use of hydraulic

fracturing, an essential completion technique that

facilitates production

and natural gas otherwise trapped

in lower permeability rock formations.

A range of local, state,

national laws and regulations currently

govern hydraulic

fracturing operations, with hydraulic

fracturing currently

prohibited in some jurisdictions.

Although hydraulic fracturing has

been conducted for many decades,

new laws, regulations and permitting requirements

are under consideration by

various state environmental

agencies, and others which could result

in increased costs, operating restrictions,

operational delays and/or

the ability to develop oil and natural

gas resources.

Governmental restrictions on hydraulic

fracturing could impact

the overall profitability or viability

of certain of our oil and natural gas

We have adopted

principles that incorporate

established industry standards

designed to meet or exceed government

requirements.

Our practices continually evolve

as technology improves and regulations

We also are subject to certain

laws and regulations relating to

environmental remediation

obligations associated

with current and past operations.

Such laws and regulations include CERCLA and RCRA

and their state equivalents.

Longer-term expenditures are

subject to considerable uncertainty

and may fluctuate significantly.

We occasionally receive requests

for information or notices of potential

liability from the EPA

environmental agencies alleging

that we are a potentially responsible

party under CERCLA or an equivalent state

On occasion, we also have been made a party to

cost recovery litigation by

those agencies or by private

These requests, notices and lawsuits

assert potential liability for remediation

costs at various sites that

typically are not owned by us, but allegedly contain

wastes attributable to

our past operations.

December 31, 2021, there were 15 sites around

in which we were identified as

a potentially

responsible party under CERCLA and comparable

For most Superfund sites, our potential liability

will be significantly less than the total site

remediation costs

because the percentage of waste attributable

to us, versus that attributable to all other

in which we were identified as a

potentially responsible

party under CERCLA and comparable state

Capital Resources and Liquidity

ConocoPhillips

For most Superfund sites, our potential

liability will be significantly less than the total

site remediation costs

because the percentage of waste

attributable to us, versus

that attributable to all other potentially

parties, is relatively low.

Although liability of those potentially

responsible is generally joint and several for

federal sites and frequently so for state sites,

other potentially responsible parties at sites

where we are a party

typically have had the financial strength to

meet their obligations, and where they have

not, or where

potentially responsible parties could not be located,

Although liability of those potentially responsible

is generally joint and several

sites and frequently so for state

sites, other potentially responsible parties

at sites where we are a party typically

have had the financial strength

to meet their obligations, and where they

have not, or where potentially

responsible parties could not be located,

our share of liability has not increased materially.

the sites at which we are potentially responsible

are still under investigation by the EPA or the state agencies

Prior to actual cleanup, those potentially responsible

normally assess site conditions, apportion

responsibility and determine the appropriate remediation.

In some instances, we may have no liability

a settlement of liability.

Actual cleanup costs generally occur after the parties

obtain EPA or equivalent state

agency approval.

There are relatively few sites where we

are a major participant, and given the timing

amounts of anticipated expenditures, neither the

cost of remediation at those sites nor

such costs at all

CERCLA sites, in the aggregate, is expected to

have a material adverse effect on our competitive

Expensed environmental costs were $393 million

in 2020 and are expected to be about $435 million

in 2021 and 2022.

Capitalized environmental costs were $161 million

in 2020 and are expected to be about

$210 million per year in 2021 and 2022.

Many of the sites at

which we are potentially responsible

are still under investigation

or the state agencies concerned.

to actual cleanup, those potentially responsible

normally assess site conditions, apportion responsibility

determine the appropriate remediation.

In some instances, we may have

no liability or attain a settlement

Actual cleanup costs generally occur after

the parties obtain EPA

or equivalent state agency approval.

There are relatively few

sites where we are a major participant,

and given the timing and amounts of anticipated

expenditures, neither the cost of remediation

at those sites nor such costs at

all CERCLA sites, in the aggregate, is

expected to have a material

adverse effect on

our competitive or financial condition.

Expensed environmental costs

were $632 million in 2021 and are expected

to be about $642 million and

$700 million in 2022 and 2023, respectively.

Capitalized environmental

costs were $184 million in 2021 and are

expected to be about $218 million and $316 million in

2022 and 2023, respectively.

Accrued liabilities for remediation activities

are not reduced for potential recoveries from insurers

third parties and are not discounted (except those

assumed in a purchase business combination,

record on a discounted basis).

Many of these liabilities result from CERCLA,

RCRA and similar state or international laws that

require us to

undertake certain investigative and remedial

activities at sites where we conduct, or once

operations or at sites where ConocoPhillips-generated

are not reduced for potential recoveries

from insurers or other third

parties and are not discounted (except

those assumed in a purchase business combination,

which we do record on

a discounted basis).

Many of these liabilities result from CERCLA, RCRA

and similar state or international

laws that require us to

undertake certain investigative

and remedial activities at sites where we conduct

or once conducted operations

at sites where ConocoPhillips-generated

waste was disposed.

The accrual also includes a number

of sites we identified that may require environmental

remediation, but which are not currently the

CERCLA, RCRA or other agency enforcement

The laws that require or address environmental

remediation may apply retroactively and regardless

of fault, the legality of the original activities

or the current

ownership or control of sites.

The accrual also includes a number of sites we

identified that may require environmental

remediation but which are not currently

the subject of CERCLA, RCRA,

or other agency enforcement activities.

The laws that require or address

environmental remediation

retroactively and regardless

of fault, the legality of the original activities or the current

ownership or control of

If applicable, we accrue receivables for probable

insurance or other third-party

In the future, we may incur significant costs

under both CERCLA and RCRA.

insurance or other third-party recoveries.

In the future, we

may incur significant costs under both

CERCLA and RCRA.

Remediation activities vary substantially

in duration and cost from site to site, depending on the

mix of unique

site characteristics, evolving remediation technologies,

diverse regulatory agencies and enforcement

and the presence or absence of potentially liable

third parties.

Therefore, it is difficult to develop reasonable

estimates of future site remediation costs.

At December 31, 2020, our balance sheet included

total accrued environmental costs of

$180 million,

compared with $171 million at December 31,

2019, for remediation activities in the

expect to incur a substantial amount of these expenditures

in duration and cost from site to

site, depending on the mix of unique site

characteristics, evolving remediation

technologies, diverse regulatory

agencies and enforcement policies,

presence or absence of potentially liable third

Therefore, it is difficult to develop

reasonable estimates of

future site remediation costs.

At December 31, 2021, our balance sheet included total

accrued environmental costs

of $187 million, compared

with $180 million at December 31, 2020, for remediation

activities in the U.S.

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

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.

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.

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

See Item 1A—Risk Factors – We expect to continue to incur substantial capital expenditures and operating costs as

a result of our compliance with existing and future environmental laws and regulations

for information

on environmental litigatio

Capital Resources and Liquidity

ConocoPhillips

Climate Change

Continuing political and social attention to the

issue of global climate change has resulted in a broad

proposed or promulgated state, national and international

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

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.

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

European Emissions Trading Scheme (ETS), the program through

which many of the EU member

states are implementing the Kyoto Protocol.

Our cost of compliance with the EU ETS in

approximately $7 million before-tax.

The Alberta Technology Innovation and Emissions Reduction (TIER) regulation

requires any existing

facility with emissions equal to or greater than 100,000

metric tonnes of carbon dioxide, or equivalent,

per year to meet a facility benchmark intensity.

The total cost of these regulations in 2020

approximately $2 million.

possible regulation that do or could affect

our operations include:

European Emissions Trading

Scheme (ETS), the program through

which many of the EU member states are

implementing the Kyoto Protocol.

Our cost of compliance with the EU ETS in 2021 was

approximately $19

million (net share before-tax

Emissions Trading

Scheme, the program with which the U.K.

replaced the ETS.

compliance with the U.K.

ETS in 2021 was approximately

$2.8 million (net share before

The Alberta Technology

Innovation and Emissions Reduction

(TIER) regulation requires any

existing facility

with emissions equal to or greater than 100,000 metric

tonnes of carbon dioxide, or equivalent,

to meet a facility benchmark intensity.

The total cost of these regulations in 2021 was

approximately $1

million (net share before-tax)

Supreme Court decision in Massachusetts

497, 127 S.Ct.

confirmed that the EPA has the authority to regulate carbon dioxide as an “air pollutant”

Federal Clean Air Act.

announcement on March 29, 2010 (published

as “Interpretation of Regulations that

Determine Pollutants Covered by Clean Air Act

Permitting Programs,” 75 Fed.

1438 (2007), confirmed

has the authority to regulate carbon dioxide

as an “air pollutant” under the Federal Clean Air

announcement on March 29, 2010 (published as “Interpretation

of Regulations that

Determine Pollutants Covered

by Clean Air Act Permitting Programs,”

17004 (April 2, 2010)),

and the EPA’s

Department of Transportation’s joint promulgation of a Final Rule on

April 1, 2010, that triggers regulation of GHGs

under the Clean Air Act, may trigger more

based claims for damages, and may result in longer

agency review time for development projects.

announcement on January 14, 2015, outlining

a series of steps it plans to take to

address methane and smog-forming volatile organic compound

emissions from the oil and gas

government established a goal of

reducing the 2012 levels in methane emissions

from the oil and gas industry by 40 to 45 percent

Department of Transportation’s

joint promulgation of a Final Rule on April 1, 2010,

that triggers regulation of GHGs under

the Clean Air Act, may trigger more climate-based

damages, and may result in longer agency review

time for development projects.

announcement on January 14, 2015, outlining a series of steps

it plans to take to address

methane and smog-forming volatile

organic compound emissions from the

oil and gas industry.

government has announced

on September 17, 2021 the Global Methane Pledge,

initiative to reduce global methane emissions

by at least 30 percent from 2020 levels

Carbon taxes in certain jurisdictions.

Our cost of compliance with Norwegian carbon

tax legislation

in 2020 was approximately $29 million (net

share before-tax).

Our cost of compliance with Norwegian carbon legislation

were fees of approximately

$35 million (net share before

We also incur a carbon tax for

emissions from fossil fuel combustion in our

British Columbia and Alberta operations in

totaling approximately $3.5 million (net share

The agreement reached in Paris in December 2015

Conference of the Parties to the United

Nations Framework Convention on Climate

Change, setting out a process for achieving

emission reductions.

from fossil fuel combustion in our

British Columbia and Alberta operations in Canada,

approximately $5.7 million (net

share before-tax).

The agreement reached in Paris

in December 2015 at the 21

Conference of the Parties to

Nations Framework Convention

on Climate Change, setting out a process

for achieving global emission

The new administration has recommitted

the United States to the Paris

Agreement, and a significant number of U.S.

Agreement, and a

significant number of U.S.

and local governments and major corporations

headquartered in the U.S.

have also announced

related commitments.

have also announced related commitments.

administration set

a new target on

April 22, 2021 of a 50 to 52 percent reduction

in GHG emissions from 2005 levels in 2030.

In the U.S., some additional form of regulation

may be forthcoming in the future at the

federal and state levels

may be forthcoming in the future at

the federal and state

with respect to GHG emissions.

Such regulation could take any of several

forms that may result in the creation

of additional costs in the form of taxes, the restriction

of output, investments of capital to maintain

with laws and regulations, or required acquisition

or trading of emission allowances.

We are working to

continuously improve operational and energy efficiency through

resource and energy conservation throughout

Such regulation could take

any of several forms that

may result in the creation of

additional costs in the form of taxes,

the restriction of output, investments

of capital to maintain compliance with

laws and regulations, or required

acquisition or trading of emission allowances.

We are working to continuously

improve operational and energy

efficiency through resource and

energy conservation throughout

our operations.

Capital Resources and Liquidity

ConocoPhillips

Compliance with changes in laws and regulations

that create a GHG tax, emission trading scheme

that create a GHG tax, emission trading

scheme or GHG

reduction policies could significantly increase

our costs, reduce demand for fossil energy derived

impact the cost and availability of capital

our costs, reduce demand for fossil

energy derived products, impact

the cost and availability of capital

and increase our exposure to litigation.

Such laws and regulations

could also increase demand for less carbon intensive

energy sources, including natural gas.

impact on our financial performance, either positive

or negative, will depend on a number of factors,

but not limited to:

Whether and to what extent legislation or

regulation is enacted.

The timing of the introduction of such legislation

Such laws and regulations could also

increase demand for less carbon intensive

energy sources, including natural

The ultimate impact on our

financial performance, either positive or negative,

will depend on a number of factors, including but

not limited to:

Whether and to what extent legislation

or regulation is enacted.

The timing of the introduction of such legislation or

The nature of the legislation (such as a cap and trade

system or a tax on emissions)

or regulation.

The nature of the legislation (such as a cap and

trade system or a tax on emissions) or

The price placed on GHG emissions (either

by the market or through a tax).

The price placed on GHG emissions (either by the market

or through a tax).

The GHG reductions required.

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The amount and allocation of allowances.

Technological and scientific developments leading to new products or services.

Any potential significant physical effects of climate

change (such as increased severe weather events,

Technological

and scientific developments leading to new products

Any potential significant physical

effects of climate change (such

as increased severe weather events,

changes in sea levels and changes in temperature).

Whether, and the extent to which, increased compliance costs are

ultimately reflected in the prices of

our products and services.

Climate Change Litigation

Beginning in 2017, governmental and other entities

in several states in the U.S.

have filed lawsuits

and gas companies, including ConocoPhillips,

seeking compensatory damages and equitable

relief to abate

alleged climate change impacts.

Additional lawsuits with similar allegations

are expected to be filed.

amounts claimed by plaintiffs are unspecified and the legal

and factual issues involved in these cases are

unprecedented.

ConocoPhillips believes these lawsuits are

factually and legally meritless and are an

inappropriate vehicle to address the challenges

associated with climate change and will

vigorously defend

against such lawsuits.

Several Louisiana parishes and the State of Louisiana

have filed 43 lawsuits under Louisiana’s State and Local

Coastal Resources Management Act (SLCRMA)

against oil and gas companies, including ConocoPhillips,

seeking compensatory damages for contamination

and erosion of the Louisiana coastline

allegedly caused by

historical oil and gas operations.

ConocoPhillips entities are defendants

in 22 of the lawsuits and will

vigorously defend against them.

Because Plaintiffs’ SLCRMA theories are unprecedented,

there is uncertainty

about these claims (both as to scope and damages)

and any potential financial impact on the company.

Company Response to Climate-Related Risks

The company has responded by putting in place

a Sustainable Development Risk Management Standard

covering the assessment and registering of significant

and high sustainable development risks based

consequence and likelihood of occurrence.

We have developed a company-wide Climate Change Action Plan

with the goal of tracking mitigation activities

for each climate-related risk included in the corporate

Sustainable Development Risk Register.

and the extent to which, increased compliance

costs are ultimately reflected

in the prices of our

products and services.

See Item 1A—Risk Factors – Existing and future laws, regulations and internal initiatives relating to global climate

changes, such as limitations on GHG emissions may impact or limit our business plans, result in significant

expenditures, promote alternative uses of energy or reduce demand for our products

for information

on climate change litigation.

Company Response to Climate

-Related Risks

The company has responded by putting

in place a Sustainable Development Risk Management

Standard covering

the assessment and registration

of significant and high sustainable development

risks based on their consequence

and likelihood of occurrence.

We have developed a

company-wide Climate Change Action

Plan with the goal of

tracking mitigation activities for

each climate-related risk included in the corporate

Sustainable Development Risk

The risks addressed in our Climate Change Action

Plan fall into four broad categories:

Plan fall into four broad

GHG-related legislation and regulation.

GHG emissions management.

Physical climate-related impacts.

Climate-related disclosure and reporting.

Emissions are categorized into three different scopes.

Gross operated Scope 1 and Scope 2 GHG emissions

help us understand our climate transition

Scope 1 emissions are direct GHG emissions

from sources that we own or control.

Scope 2 emissions are GHG emissions from

the generation of purchased electricity or

steam that we

Scope 3 emissions are indirect emissions

from sources that we neither own nor control.

We announced in October 2020 the adoption of a Paris-aligned climate risk framework

Physical climate-related

Climate-related disclosure

and reporting.

Emissions are categorized

into three different

Gross operated and net

equity Scope 1 and Scope 2 GHG

emissions help us understand our climate

transition risk.

Scope 1 emissions are direct GHG emissions from

sources that we control

or in which we have

ownership interest.

Scope 2 emissions are indirect GHG emissions

from the generation of purchased

electricity or steam that

Scope 3 emissions are indirect emissions from

sources that we neither own nor control.

Capital Resources and Liquidity

ConocoPhillips

We announced in October 2020 the adoption

of a Paris-aligned climate risk framework

with the objective of

implementing a coherent set of choices designed

to facilitate the success of our existing exploration

to facilitate the success

of our existing exploration

production business through the energy transition.

Given the uncertainties remaining about how the

transition will evolve, the strategy aims to be robust

across a range of potential future outcomes.

The strategy is comprised of four pillars:

Our target framework consists of a hierarchy of targets, from a long-term

ambition that sets

the direction and aim of the strategy, to a medium-term performance target for GHG emissions

intensity, to shorter-term targets for flaring and methane intensity reductions.

targets are supported by lower-level internal business

unit goals to enable the company to achieve the

company-wide targets.

We have set a target to reduce our gross operated (scope 1 and 2) emissions

intensity by 35 to 45 percent from 2016 levels by

2030, with an ambition to achieve net-zero

Given the uncertainties remaining about

how the energy

transition will evolve, the strategy

aims to be robust across a range

of potential future outcomes.

The strategy is comprised of four

Our target framework

consists of a hierarchy

of targets, from a long-term ambition

that sets the

direction and aim of the strategy,

to a medium-term performance target

for GHG emissions intensity,

shorter-term targets for

flaring and methane intensity reductions.

These performance targets are

supported by lower-level internal

business unit goals to enable the company to

achieve the company-

wide targets.

In September 2021, we increased our interim

operational target and

have set it to reduce

our gross operated and net

equity (scope 1 and 2) emissions intensity by

40 to 50 percent from 2016

levels by 2030, an improvement

from the previously announced target

of 35 to 45 percent on only a gross

operated basis, with an ambition to

achieve net-zero operated

emissions by 2050.

We have joined the World

Bank Flaring Initiative to work towards

flaring of gas by 2030.

We have joined the

World Bank Flaring Initiative to

work towards zero

routine flaring of associated gas

by 2030, with an

ambition to meet that goal by 2025.

Technology choices:

We expanded our Marginal Abatement Cost Curve process to provide a broader

range of opportunities for emission reduction

We expanded our Marginal

Abatement Cost Curve process

to provide a broader

range of opportunities for emission

reduction technology.

Portfolio choices:

Our corporate authorization process requires

all qualifying projects to include a

GHG price in their project approval economics.

Different GHG prices are used depending on the

region or jurisdiction.

Projects in jurisdictions with existing GHG

pricing regimes incorporate the

existing GHG price and forecast into their

Projects where no existing GHG pricing

regime exists utilize a scenario forecast from our

internally consistent World Energy Model.

way, both existing and emerging regulatory requirements are considered in our decision-making.

company does not use an estimated market cost

of GHG emissions when assessing reserves

jurisdictions without existing GHG regulations.

Our corporate

authorization process requires

all qualifying projects to include a GHG

price in their project approval economics.

Different GHG prices are used

depending on the region or

jurisdiction.

Projects in jurisdictions with existing GHG pricing regimes

incorporate the existing

and forecast into

their economics.

Projects where no existing GHG pricing regime

exists utilize a scenario

forecast from our internally

consistent World

Energy Model.

both existing and emerging

regulatory requirements are

considered in our decision-making.

The company does not use an estimated

market cost of GHG emissions when assessing

reserves in jurisdictions without existing GHG regulations

This is in contrast to changes

to the cost of existing GHG emission

regulations which can impact our

reserves calculations.

External engagement:

Our external engagement

aims to differentiate ConocoPhillips within the oil and

gas sector with our approach to managing climate-related

engagement aims to differentiate

ConocoPhillips within the oil and

gas sector with our approach to managing

climate-related risk.

We are a Founding Member of the

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policy institute founded in collaboration

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

alignment with our public policy principles.

We also belong to and fund Americans For Carbon

Dividends, the education and advocacy branch of

with business

and environmental interests

to develop a carbon dividend plan.

Participation in the CLC provides

opportunity for ongoing dialogue about carbon

pricing and framing the issues in alignment with our

policy principles.

We also belong to and fund Americans For

Carbon Dividends, the education and

advocacy branch of the CLC.

ConocoPhillips

Critical Accounting Estimates

The preparation of financial statements

in conformity with GAAP requires management

to select appropriate

accounting policies and to make estimates and

assumptions that affect the reported amounts of assets,

liabilities, revenues and expenses.

See Note 1—Accounting Policies, in the Notes

to Consolidated Financial

Statements, for descriptions of our major accounting

Certain of these accounting policies involve

judgments and uncertainties to such an extent there

is a reasonable likelihood materially different amounts

would have been reported under different conditions, or if

different assumptions had been used.

These critical

accounting estimates are discussed with the Audit

and Finance Committee of the Board of Directors at

We believe the following discussions of critical accounting estimates, along

with the discussion of

deferred tax asset valuation allowances in this

report, address all important accounting

areas where the nature

of accounting estimates or assumptions is material

due to the levels of subjectivity and judgment necessary

account for highly uncertain matters or the

susceptibility of such matters to change.

in conformity with GAAP requires

management to select appropriate

accounting policies and to make

estimates and assumptions that

affect the reported amounts

of assets, liabilities,

revenues and expenses.

for descriptions of our major accounting policies.

Certain of these accounting

policies involve judgments and uncertainties

to such an extent there is a reasonable

likelihood materially different

amounts would have been reported

under different conditions,

or if different assumptions had been

critical accounting estimates are

discussed with the Audit and Finance Committee of the Board

of Directors at least

We believe the following discussions

of critical accounting estimates address

all important accounting

areas where the nature of accounting

estimates or assumptions is material

due to the levels of subjectivity and

judgment necessary to account for

highly uncertain matters or

the susceptibility of such matters to

Oil and Gas Accounting

Accounting for oil and gas exploratory activity

is subject to special accounting rules unique

to the oil and gas

The acquisition of G&G seismic information,

prior to the discovery of proved reserves, is

as incurred, similar to accounting for research and

development costs.

However, leasehold acquisition costs

and exploratory well costs are capitalized on the

balance sheet pending determination of whether

and gas reserves have been recognized.

Accounting for oil and gas activity

is subject to special accounting rules unique to the oil

and gas industry.

acquisition of G&G seismic information, prior to

the discovery of proved reserves,

is expensed as incurred, similar

to accounting for research

and development costs.

leasehold acquisition costs and exploratory

costs are capitalized

on the balance sheet pending determination of whether

proved oil and gas reserves

been recognized.

Property Acquisition Costs

At year-end 2021, we held $9.3 billion

of net capitalized unproved

property costs which consisted

individually significant and pooled leaseholds, mineral

rights held in perpetuity by title ownership,

wells currently being drilled, and to a lesser

extent, suspended exploratory

wells and capitalized interest.

amount increased by $6.9 billion at December 31, 2021 as compared

to December 31, 2020, primarily due to the

Concho and Shell Permian acquisitions

in the Permian Basin where we have an ongoing

significant and active

development program.

Outside of the Permian Basin, the remaining

$2.0 billion is concentrated

development areas.

Management periodically assesses our unproved

property for impairment based on the

results of exploration and

drilling efforts and the outlook for commercialization.

For individually significant leaseholds, management

periodically assesses for impairment based on

and drilling efforts to date.

For relatively small individual leasehold acquisition

periodically assesses for impairment based

on exploration and

drilling efforts to date.

For insignificant individual leasehold acquisition

costs, management exercises

judgment and determines a percentage probability

that the prospect ultimately will fail to find

proved oil and

gas reserves and pools that leasehold information

with others in the geographic area.

For prospects in areas

with limited, or no, previous exploratory drilling,

the percentage probability of ultimate failure

judged to be quite high.

and determines a percentage probability

that the prospect ultimately will fail to

find proved oil and gas reserves,

including estimates of future expirations,

and pools that leasehold information with others

in similar geographic

For prospects in areas with limited, or

no, previous exploratory

drilling, the percentage probability of

ultimate failure is normally judged

to be quite high.

This judgmental percentage is multiplied

by the leasehold acquisition cost, and that

product is divided by the contractual period

of the leasehold to determine a periodic leasehold

charge that is reported in exploration expense.

This judgmental probability percentage is reassessed

adjusted throughout the contractual period of the

leasehold based on favorable or unfavorable

activity on the leasehold or on adjacent leaseholds,

and leasehold impairment amortization expense is

prospectively.

At year-end 2020, the remaining $2.4 billion of net capitalized

unproved property costs consisted primarily

individually significant leaseholds, mineral rights

held in perpetuity by title ownership, exploratory

currently being drilled, suspended exploratory

wells, and capitalized interest.

Of this amount, approximately

$1.9 billion is concentrated in 10 major development

areas, the majority of which are not expected to

proved properties in 2021.

Management periodically assesses individually

significant leaseholds for

impairment based on the results of exploration

and drilling efforts and the outlook for commercialization.

by the leasehold

acquisition cost, and that product is

divided by the contractual period of the leasehold to

determine a periodic

leasehold impairment charge that is

reported in exploration expense.

This judgmental probability percentage

reassessed and adjusted throughout

the contractual period of the leasehold based on favorable

or unfavorable

exploratory activity on the leasehold or

on adjacent leaseholds, and leasehold impairment amortization

adjusted prospectively.

Exploratory Costs

For exploratory wells, drilling costs are temporarily

capitalized, or “suspended,” on the balance sheet,

a determination of whether potentially economic

oil and gas reserves have been discovered by the

effort to justify development.

If exploratory wells encounter potentially economic

quantities of oil and gas, the well costs

remain capitalized

on the balance sheet as long as sufficient progress assessing

the reserves and the economic and operating

viability of the project is being made.

The accounting notion of “sufficient progress” is

a judgmental area, but

the accounting rules do prohibit continued capitalization

For exploratory wells, drilling

costs are temporarily capitalized,

or “suspended,”

on the balance sheet, pending a

determination of whether potentially economic

oil and gas reserves have

been discovered by the drilling effort

justify development.

ConocoPhillips

If exploratory wells encounter

potentially economic quantities of oil and gas,

the well costs remain capitalized

the balance sheet as long as sufficient progress

assessing the reserves and the economic and operating

the project is being made.

The accounting notion of “sufficient

progress” is a judgmental area,

but the accounting

rules do prohibit continued capitalization

of suspended well costs on the expectation

market conditions will improve or new technologies

will be found that would make the development

future market conditions will

improve or new technologies will be found

that would make the development

economically profitable.

Often, the ability to move into the development

phase and record proved reserves is

dependent on obtaining permits and government

or co-venturer approvals, the timing of which is

ability to move into the development

phase and record proved

reserves is dependent on obtaining permits and

government or co-venturer

approvals, the timing of which is ultimately

beyond our control.

Exploratory well costs remain suspended as long

as we are actively pursuing such

approvals and permits, and believe they will be obtained.

Once all required approvals and permits have

obtained, the projects are moved into the development

phase, and the oil and gas reserves are designated

proved reserves.

For complex exploratory discoveries, it

is not unusual to have exploratory wells remain

suspended on the balance sheet for several

years while we perform additional appraisal

drilling and seismic

work on the potential oil and gas field or while

we seek government or co-venturer approval of development

plans or seek environmental permitting.

Once a determination is made the well did not

encounter potentially

economic oil and gas quantities, the well costs

are expensed as a dry hole and reported in

exploration expense.

Management reviews suspended well balances quarterly, continuously monitors

the results of the additional

appraisal drilling and seismic work, and expenses

the suspended well costs as a dry hole when it

the potential field does not warrant further

investment in the near term.

Criteria utilized in making this

determination include evaluation of the reservoir

characteristics and hydrocarbon properties,

development costs, ability to apply existing technology

to produce the reserves, fiscal terms,

regulations or

contract negotiations, and our expected return

on investment.

At year-end 2020,

total suspended well costs were $682 million,

compared with $1,020 million at year-end

For additional information on suspended wells,

including an aging analysis, see Note 7—Suspended

Wells and Exploration Expenses, in the Notes to Consolidated Financial Statements.

Exploratory well costs

remain suspended as long as we are actively pursuing

such approvals and permits, and believe they will be

Once all required approvals

and permits have been obtained, the projects

are moved into the

development phase, and the oil and gas

reserves are designated as proved

At year-end 2021, total suspended

well costs were $660 million, compared

with $682 million at year-end 2020.

For additional information on suspended

wells, including an aging analysis,

Proved Reserves

Engineering estimates of the quantities of proved reserves

are inherently imprecise and represent only

approximate amounts because of the judgments involved

in developing such information.

Reserve estimates

are based on geological and engineering assessments

of in-place hydrocarbon volumes, the production

historical extraction recovery and processing yield

factors, installed plant operating capacity

Engineering estimates of the quantities of proved

reserves are inherently imprecise and

represent only

approximate amounts because

of the judgments involved in developing

such information.

Reserve estimates are

based on geological and engineering assessments of in-place

hydrocarbon volumes,

the production plan, historical

extraction recovery and processing

yield factors, installed plant

operating capacity and approved

operating limits.

The reliability of these estimates at any point

in time depends on both the quality and

quantity of the technical and economic data

and the efficiency of extracting and processing the

hydrocarbons.

Despite the inherent imprecision in these engineering

estimates, accounting rules require disclosure

“proved” reserve estimates due to the importance

of these estimates to better understand the perceived

and future cash flows of a company’s operations.

There are several authoritative guidelines

regarding the

engineering criteria that must be met before estimated

The reliability of these estimates at

any point in time depends on both the quality and quantity

of the technical and

economic data and the efficiency of extracting

and processing the hydrocarbons.

Despite the inherent imprecision in

these engineering estimates, accounting

rules require disclosure of “proved”

reserve estimates due to the importance

of these estimates to better

understand the perceived value

cash flows of a company’s

There are several authoritative

guidelines regarding the engineering criteria

that must be met before estimated

reserves can be designated as “proved.”

geosciences and reservoir engineering organization

has policies and procedures in place consistent

authoritative guidelines.

We have trained and experienced internal engineering personnel who estimate

proved reserves held by consolidated companies, as

well as our share of equity affiliates.

Proved reserve estimates are adjusted annually

in the fourth quarter and during the year

if significant changes

occur, and take into account recent production and subsurface

information about each field.

Also, as required

by current authoritative guidelines, the estimated

future date when an asset will reach the end

of its economic

life is based on 12-month average prices and current

This date estimates when production will end and

affects the amount of estimated reserves.

Therefore, as prices and cost levels change from

year to year, the

estimate of proved reserves also changes.

Generally, our proved reserves decrease as prices decline and

increase as prices rise.

Our proved reserves include estimated quantities

related to PSCs, reported under the “economic interest”

method, as well as variable-royalty regimes,

and are subject to fluctuations in commodity

Our geosciences and reservoir

engineering organization has

policies and procedures in place consistent

with these authoritative guidelines.

have trained and experienced

internal engineering personnel who estimate

our proved reserves held by

consolidated companies, as well as our share

of equity affiliates.

See Oil and Gas supplemental disclosures for

additional information.

Proved reserve estimates are

adjusted annually in the fourth quarter

and during the year if significant changes

take into account

recent production and subsurface information

about each field.

Also, as required by

current authoritative guidelines,

the estimated future date

when an asset will reach the end of its economic life is

based on 12-month average prices

and current costs.

This date estimates when production

will end and affects

the amount of estimated reserves.

Therefore, as prices and cost

levels change from year to year,

the estimate of

proved reserves also changes.

Generally, our

proved reserves decrease as prices

decline and increase as prices

Our proved reserves include estimat

ed quantities related to PSCs, reported

under the “economic interest”

method, as well as variable-royalty

regimes, and are subject to fluctuations

in commodity prices;

operating expenses;

and capital costs.

If costs remain stable, reserve quantities

attributable to recovery of costs

will change inversely to changes in commodity

We would expect reserves from these contracts to

decrease when product prices rise and increase

when prices decline.

The estimation of proved developed reserves also

is important to the income statement because

developed reserve estimate for a field serves as the

denominator in the unit-of-production

calculation of the

DD&A of the capitalized costs for that asset.

At year-end 2020, the net book value of productive PP&E

subject to a unit-of-production calculation was

approximately $33 billion and the DD&A recorded

assets in 2020 was approximately $5.3 billion.

The estimated proved developed reserves for

our consolidated

operations were 3.2 billion BOE at the end

of 2019 and 2.5 billion BOE at the end of

If the estimates of

proved reserves used in the unit-of-production

calculations had been lower by 10 percent

calculations, before-tax DD&A in 2020

would have increased by an estimated $588

Long-lived assets used in operations are assessed

for impairment whenever changes in facts

and circumstances

will change inversely to changes

in commodity prices.

We would expect reserves

from these contracts to

when product prices rise and increase when prices decline.

The estimation of proved reserves

is also important to the income statement

because the proved reserve estimate

for a field serves as the denominator in the unit-of-production

calculation of the DD&A of the capitalized costs

for that asset.

At year-end 2021, the net book value of productive

PP&E subject to a unit-of-production

was approximately $52 billion

and the DD&A recorded on these assets in

2021 was approximately $7.0 billion.

estimated proved reserves

for our consolidated operations

were 2.5 billion BOE at the end of 2020 and 4.0 billion

BOE at the end of 2021.

If the estimates of proved reserves

used in the unit-of-production

calculations had been

lower by 10 percent across all calculations,

before-tax DD&A in 2021 would have

increased by an estimated

$774 million.

ConocoPhillips

Business Combination—Valuation

of Oil and Gas Properties

For recent transactions, management

applied the principles of acquisition accounting under FASB

ASC Topic 805

“Business Combinations” and allocated the purchase

price to assets acquired and liabilities assumed, based

their estimated fair values as

of the acquisition date.

Estimating the fair values involved

making various

assumptions, of which the most significant assumptions

relate to the fair values assigned

to proved and unproved

oil and gas properties.

Management utilized a discounted

cash flow approach, based on market participant

assumptions, and engaged third party

valuation experts in preparing fair value

Significant inputs incorporated

within the valuation include future commodity price assumptions

and production

profiles of reserve estimates, the

pace of drilling plans, future operating and development

costs, inflation rates,

and discount rates using a market

-based weighted average

cost of capital determined at the

When estimating the fair value of unproved

properties, additional risk-weighting

adjustments are

applied to probable and possible reserves.

The assumptions and inputs incorporated

within the fair value estimates are

subject to considerable management

judgement and are based on industry,

market, and economic conditions prevalent

at the time of the acquisition.

Although we based these estimates on assumptions

believed to be reasonable, these estimates

are inherently

unpredictable and uncertain and actual results

could differ.

Long-lived assets used in operations

are assessed for impairment whenever changes

in facts and circumstances

indicate a possible significant deterioration

in future cash flows expected to be generated

by an asset group.

there is an indication the carrying amount of

an asset may not be recovered, a recoverability

test is performed

using management’s assumptions for prices, volumes and future development

If, upon review, the sum

of the undiscounted cash flows before income-taxes

is less than the carrying value of the asset

carrying value is written down to estimated fair

value and reported as impairments in the

periods in which the

determination is made.

Individual assets are grouped for impairment

purposes at the lowest level for which

there are identifiable cash flows that are largely independent

of the cash flows of other groups of assets—

generally on a field-by-field basis for E&P assets.

Because there usually is a lack of quoted

market prices for

long-lived assets, the fair value of impaired assets

is typically determined based on the present

expected future cash flows using discount rates

and prices believed to be consistent with

those used by

principal market participants,

or based on a multiple of operating cash flow validated

with historical market

transactions of similar assets where possible.

The expected future cash flows used for

impairment reviews and

related fair value calculations are based on estimated

future production volumes, commodity

prices, operating

costs and capital decisions, considering all

available information at the date of review.

Differing assumptions

could affect the timing and the amount of an impairment

in any period.

See Note 8—Impairments, in the

Notes to Consolidated Financial Statements,

for additional information.

Investments in nonconsolidated entities

accounted for under the equity method are assessed

for impairment

whenever changes in the facts and circumstances indicate

a loss in value has occurred.

Such evidence of a loss

in value might include our inability to

recover the carrying amount, the lack of sustained

earnings capacity

which would justify the current investment amount,

or a current fair value less than the investment’s carrying

in the future cash flows expected

to be generated by an

there is an indication the carrying amount

of an asset may not be recovered,

a recoverability test

using management’s assumptions

for prices, volumes and future development

If the sum of the

undiscounted cash flows before

income-taxes is less than

the carrying value of the asset group, the carrying

is written down to estimated fair

value and reported as an impairment

in the periods in which the determination is

Individual assets are grouped for

impairment purposes at the lowest level for

which there are identifiable

cash flows that are largely independent

of the cash flows of other groups of assets—generally

on a field-by-field

basis for E&P assets.

Because there usually is a lack of quoted market

prices for long-lived assets, the fair

impaired assets is typically determined based

on the present values of expected

future cash flows using discount

rates and prices believed to

be consistent with those used by principal

market participants, or based on a multiple

of operating cash flow validated

with historical market transactions

of similar assets where possible.

The expected future cash flows used

for impairment reviews and

related fair value calculations

estimated future production volumes,

commodity prices, operating costs

and capital decisions, considering all

available evidence at the date of review.

Differing assumptions could

affect the timing and the amount of an

impairment in any period.

Investments in nonconsolidated

entities accounted for under the equity

method are assessed for impairment

whenever changes in the facts and circumstances

indicate a loss in value has occurred.

Such evidence of a loss in

value might include our inability to recover

the carrying amount, the lack of sustained earnings

capacity which

would justify the current investment

amount, or a current fair value

less than the investment’s

carrying amount.

When such a condition is judgmentally determined

to be other than temporary, an impairment charge

is recognized for the difference between the investment’s carrying value and its estimated

to be other than temporary,

an impairment charge is

recognized for the difference

between the investment’s

carrying value and its estimated fair

determining whether a decline in value is other than

temporary, management considers factors such as the

length of time and extent of the decline, the investee’s financial condition

and near-term prospects, and our

ability and intention to retain our investment for

a period that will be sufficient to allow for any anticipated

recovery in the market value of the investment.

Since quoted market prices are usually not

available, the fair

value is typically based on the present value

of expected future cash flows using discount

rates and prices

believed to be consistent with those used by principal

market participants, plus market analysis

of comparable

assets owned by the investee, if appropriate.

Differing assumptions could affect the timing and the amount of

an impairment of an investment in any period.

See the “APLNG” section of Note 5—Investments,

Long-Term Receivables,

in the Notes to Consolidated Financial

Statements, for additional information.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations,

we have material legal obligations to remove

equipment and restore the land or seabed at the

end of operations at operational sites.

Our largest asset

removal obligations involve plugging and abandonment

of wells, removal and disposal of offshore oil and

platforms around the world, as well as oil and gas

management considers factors

such as the length

of time and extent of the decline, the investee’s

financial condition and near-term prospects,

and our ability and

intention to retain our

investment for a period that

will be sufficient to allow for any

anticipated recovery in the

market value of the investment.

Since quoted market prices are usually

not available, the fair value is typically

based on the present value of expected future

cash flows using discount

rates and prices believed to be consistent

with those used by principal market participants,

plus market analysis of comparable

assets owned by the

investee, if appropriate.

Differing assumptions could affect

the timing and the amount of an impairment of an

investment in any period.

See the “APLNG” section

ConocoPhillips

Asset Retirement Obligations

and Environmental Costs

Under various contracts, permits

and regulations, we have material

legal obligations to remove

equipment and restore the land or

seabed at the end of operations at operational

Our largest asset removal

obligations involve

plugging and abandonment of wells, removal and disposal

of offshore oil and gas platforms

around the world, as well as oil and gas

production facilities and pipelines in Alaska.

The fair values

of obligations for dismantling and removing these

facilities are recorded as a liability and

an increase to PP&E

at the time of installation of the asset based on estimated

discounted costs.

Fair value is estimated using a

present value approach, incorporating assumptions

about estimated amounts and timing of settlements

Fair value is estimated using

present value approach,

incorporating assumptions about estimated

amounts and timing of settlements and

impacts of the use of technologies.

Estimating future asset removal costs requires

significant judgement.

of these removal obligations are many years, or decades,

Estimating future asset removal

costs requires significant

these removal obligations are

many years, or decades,

in the future and the contracts and regulations

have vague descriptions of what removal practices

and criteria must be met when the removal

event actually

vague descriptions of what removal

practices and criteria must be met when the removal

event actually occurs.

The carrying value of our asset retirement

obligation estimate is sensitive to inputs such as asset

removal technologies and costs, regulatory and other

compliance considerations, expenditure timing,

inputs into valuation of the obligation, including

discount and inflation rates, which are all

subject to change

between the time of initial recognition of the liability

and future settlement of our obligation.

Normally, changes in asset removal obligations are reflected in the income statement

as increases or decreases

to DD&A over the remaining life of the assets.

However, for assets at or nearing the end of their operations, as

well as previously sold assets for which we

retained the asset removal obligation, an increase

removal obligation can result in an immediate

charge to earnings, because any increase in PP&E

increased obligation would immediately be subject

to impairment, due to the low fair value of these

In addition to asset removal obligations, under the

above or similar contracts, permits and regulations,

certain environmental-related projects.

obligation estimate is sensitive

to inputs such as asset removal

technologies and costs, regulatory

and other compliance considerations,

expenditure timing, and other inputs into

valuation of the obligation,

including discount and inflation rates,

which are all subject to change between the time

of initial recognition of the liability and future settlement

of our obligation.

Normally, changes

in asset removal obligations

are reflected in the income statement

as increases or decreases to

DD&A over the remaining life of the assets.

for assets at or nearing the end of their operations,

as previously sold assets for which we retained

the asset removal obligation,

an increase in the asset removal

obligation can result in an immediate charge

to earnings, because any increase

in PP&E due to the increased

obligation would immediately

be subject to impairment, due to the low fair value

of these properties.

In addition to asset removal obligations,

under the above or similar contracts, permits

and regulations, we have

certain environmental-related

These are primarily related to remediation

activities required by

Canada and various states

within the U.S.

at exploration and production sites.

Future environmental

remediation costs are difficult to estimate because they are

subject to change due to such factors as the

uncertain magnitude of cleanup costs, the unknown

time and extent of such remedial actions

required, and the determination of our liability

in proportion to that of other responsible parties.

Asset Retirement Obligations and Accrued Environmental

Costs, in the Notes to Consolidated Financial

Statements, for additional information.

activities required by Canada

and various states within the U.S.

at exploration and production

Future environmental remediation

difficult to estimate because they

are subject to change due to such factors

as the uncertain magnitude of cleanup

costs, the unknown time and extent of such

remedial actions that may be required,

and the determination of our

liability in proportion to that of other responsible

Projected Benefit Obligations

Determination of the projected benefit obligations

for our defined benefit pension and postretirement

important to the recorded amounts for such obligations

on the balance sheet and to the amount of benefit

expense in the income statement.

The actuarial determination of projected benefit

obligations and company

contribution requirements involves judgment about

uncertain future events, including estimated

dates, salary levels at retirement, mortality

rates, lump-sum election rates, rates of return on plan

assets, future

health care cost-trend rates, and rates of utilization

of health care services by retirees.

Due to the specialized

nature of these calculations, we engage outside actuarial

firms to assist in the determination of these

benefit obligations and company contribution requirements.

For Employee Retirement Income Security Act-

governed pension plans, the actuary exercises fiduciary

care on behalf of plan participants in the

determination

of the judgmental assumptions used in determining

required company contributions into the

differing objectives and requirements between financial

accounting rules and the pension plan funding

regulations promulgated by governmental agencies,

the actuarial methods and assumptions

purposes differ in certain important respects.

Ultimately, we will be required to fund all vested benefits under

pension and postretirement benefit plans not

funded by plan assets or investment returns,

but the judgmental

assumptions used in the actuarial calculations

significantly affect periodic financial statements and funding

patterns over time.

Projected benefit obligations are particularly

sensitive to the discount rate assumption.

100 basis-point decrease in the discount rate assumption

contribution requirements involves

judgment about uncertain future events,

including estimated retirement

dates, salary levels at retirement,

mortality rates, lump-sum election rates,

rates of return on plan assets,

future health care cost-trend rates,

rates of utilization of health

care services by retirees.

Due to the specialized nature of these

calculations, we

engage outside actuarial firms to assist

in the determination of these projected benefit

obligations and company

contribution requirements.

we will be required to fund all vested

benefits under pension and

postretirement benefit plans

not funded by plan assets or investment

returns, but the judgmental assumptions

used in the actuarial calculations significantly affect

periodic financial statements and

funding patterns over time.

Projected benefit obligations

are particularly sensitive to the discount

rate assumption.

A 100 basis-point decrease

in the discount rate assumption

would increase projected benefit obligations

$1,200 million.

Benefit expense is sensitive to the discount rate

by $1.0 billion.

Benefit expense is

sensitive to the discount rate

and return on plan assets assumptions.

100 basis-point decrease in the discount rate assumption

would increase annual benefit expense by

$110 million, while a 100 basis-point decrease in the return

on plan assets assumption would increase annual

benefit expense by $80 million.

In determining the discount rate, we use yields

on high-quality fixed income

investments matched to the estimated benefit

cash flows of our plans.

A 100 basis-point decrease in the discount

rate assumption would increase

annual benefit expense by $70 million, while a 100 basis-point

decrease in the

return on plan assets assumption would increase

annual benefit expense by $60 million.

In determining the

discount rate, we use yields

on high-quality fixed income investments

matched to the estimated benefit

of our plans.

We are also exposed to the possibility

that lump sum retirement benefits taken from pension

plans during the year could exceed the total of

and interest components of annual pension expense

and trigger accelerated recognition of a portion

unrecognized net actuarial losses and gains.

These benefit payments are based on decisions

participants and are therefore difficult to predict.

In the event there is a significant reduction in the

years of future service of present employees or the

elimination of the accrual of defined benefits

for some or all

of their future services for a significant number

of employees, we could recognize a curtailment

gain or loss.

See Note 17—Employee Benefit Plans, in the

Notes to Consolidated Financial Statements,

for additional

that lump sum retirement benefits taken

from pension plans

during the year could exceed the

total of service and interest components

of annual pension expense and

trigger accelerated recognition

of a portion of unrecognized net actuarial

losses and gains.

These benefit

payments are based on decisions by plan

participants and are therefore difficult

In the event there is a

significant reduction in the expected years

of future service of present employees or the elimination

of the accrual

of defined benefits for some or all of their future

services for a significant number of employees,

recognize a curtailment gain

ConocoPhillips

Contingencies

A number of claims and lawsuits are made against

the company arising in the ordinary course of

Management exercises judgment related to accounting

and disclosure of these claims which includes

damages, and underpayments associated with environmental

remediation, tax, contracts, and other legal

the company arising in the ordinary course

Management exercises

judgment related to accounting

and disclosure of these claims which includes losses,

damages, and underpayments associated

with environmental remediation,

tax, contracts, and

other legal disputes.

As we learn new facts concerning contingencies,

we reassess our position both with respect to

amounts recognized and disclosed considering changes

we reassess our position both with respect to amounts

recognized and disclosed considering changes

to the probability of additional losses and potential

However, actual losses can and do vary from estimates

for a variety of reasons including legal,

arbitration, or other third-party decisions;

actual losses can and do vary from estimates

for a variety of reasons

including legal, arbitration, or other

third-party decisions;

settlement discussions;

evaluation of scope of damages;

interpretation of regulatory or contractual terms;

expected timing of future actions;

and proportion

shared with other responsible parties.

Estimated future costs related to contingencies

are subject to change as

events evolve and as additional information becomes

available during the administrative and litigation

For additional information on contingent

liabilities, see the “Contingencies” section

within “Capital

Resources and Liquidity” and Note 12—Contingencies

and Commitments, in the Notes to Consolidated

Financial Statements.

We are subject to income taxation in numerous jurisdictions worldwide.

We record deferred tax assets and

liabilities to account for the expected future tax

consequences of events that have been recognized

financial statements and our tax returns.

We routinely assess our deferred tax assets and reduce such assets by

a valuation allowance if we deem it is more

likely than not that some portion, or all,

of the deferred tax assets

will not be realized.

interpretation

of regulatory or

contractual terms;

timing of future actions;

and proportion of liability

shared with other responsible

Estimated future costs related

to contingencies are subject to

change as events evolve and as additional

information becomes available

during the administrative and litigation

For additional information on

contingent liabilities, see the “Contingencies”

section within “Capital Resources and

Liquidity” and

We are subject to income taxation

in numerous jurisdictions worldwide.

We record deferred

tax assets and

liabilities to account for the expected

future tax consequences of events

that have been recognized

in our financial

statements and our tax

We routinely assess our deferred

tax assets and reduce such assets

by a valuation

allowance if we deem it is more likely than

not that some portion,

or all, of the deferred tax assets

In assessing the need for adjustments

to existing valuation allowances, we consider all

available positive and negative evidence.

evidence includes reversals of temporary

forecasts of future taxable income, assessment of

future business assumptions and applicable

strategies that are prudent and feasible.

evidence includes losses in recent years

as well as the

forecasts of future net income (loss) in the realizable

to existing valuation allowances,

we consider all available positive

and negative evidence.

Positive evidence includes reversals

of temporary differences,

forecasts of future taxable

income, assessment of future business assumptions

and applicable tax planning strategies

that are prudent and

Negative evidence includes losses

in recent years as well as the forecasts

of future net income (loss) in

the realizable period.

In making our assessment regarding

allowances, we weight the evidence based on

Numerous judgments and assumptions are inherent

in the determination of future taxable income, including

factors such as future operating conditions

assessment of the effects of foreign taxes on our U.S.

income taxes (particularly as related to prevailing

oil and gas prices).

See Note 18—Income Taxes for additional information, in the Notes to Consolidated

Financial Statements.

We regularly assess and, if required, establish accruals for uncertain tax positions that

could result from

assessments of additional tax by taxing jurisdictions

in countries where we operate.

We recognize a tax benefit

from an uncertain tax position when it is more

likely than not that the position will be sustained

examination, based on the technical merits

of the position.

These accruals for uncertain tax positions are

subject to a significant amount of judgment and

are reviewed and adjusted on a periodic basis

changing facts and circumstances considering the

progress of ongoing tax audits, court proceedings,

applicable tax laws, including tax case rulings and

legislative guidance, or expiration of the

applicable statute

valuation allowances, we weight

the evidence based on

Numerous judgments and assumptions are

inherent in the determination of future taxable

including factors such as future operating

conditions and the assessment of the effects

of foreign taxes

federal income taxes

(particularly as related to prevai

ling oil and gas prices).

We regularly assess and, if required,

establish accruals for uncertain tax

positions that could result from

assessments of additional tax by taxing

jurisdictions in countries where we operate.

We recognize a tax

from an uncertain tax position when it

is more likely than not that the

position will be sustained upon examination,

based on the technical merits of the position.

These accruals for uncertain tax positions

are subject to a significant

amount of judgment and are reviewed

and adjusted on a periodic basis in light of changing facts

circumstances considering the progress

of ongoing tax audits, court proceedings,

changes in applicable tax laws,

including tax case rulings and legislative guidance,

or expiration of the applicable statute

of limitations.

See Note 18—Income Taxes for additional information, in the Notes to Consolidated

CAUTIONARY STATEMENT

FOR THE PURPOSES OF THE “SAFE HARBOR”

PROVISIONS OF

SECURITIES LITIGATION REFORM ACT OF 1995

regarding discussion of critical accounting

estimates on deferred

tax valuation allowances.

ConocoPhillips

Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the

Private Securities Litigation Reform Act

This report includes forward-looking statements

within the meaning of Section 27A of the Securities

1933 and Section 21E of the Securities Exchange

All statements other than statements of

historical fact included or incorporated by reference in

this report, including, without limitation,

regarding our future financial position, business

strategy, budgets, projected revenues, projected costs and

plans, objectives of management for future operations,

the anticipated benefits of the transaction

and Concho, the anticipated impact of the transaction

on the combined company’s business and future

financial and operating results, the expected amount

and the timing of synergies from the transaction

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

included or incorporated by

reference in this report, including, without

limitation, statements

regarding our future

financial position, business strategy,

budgets, projected revenues,

projected costs and plans, objectives

management for future operatio

ns and the anticipated impact of the Shell Enterprise

LLC (Shell) transaction on the

company’s business

and future financial and operating results 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

forward-looking statements

contained in this report include our expected

production growth and outlook

business environment generally,

our expected capital budget and

capital expenditures, and discussions

future dividends.

You can often identify our forward-

looking statements by the words “anticipate,” “believe,”

“budget,” “continue,” “could,” “effort,” “estimate,”

“expect,” “forecast,” “intend,” “goal,” “guidance,”

“may,” “objective,” “outlook,” “plan,” “potential,”

“predict,” “projection,” “seek,” “should,” “target,” “will,”

“would” and similar expressions.

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

and projections about

ourselves and the industries in which we operate in

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.

You can often identify

our forward-looking statements

by the words “anticipate,”

“plan,” “potential,”

“predict,” “projection,”

“will,” “would” and

similar expressions.

We based the forward-looking

statements on our current

expectations, estimates and

projections about ourselves

and the industries in which we operate in

We caution you these

statements are not guarantees

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

-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-

our actual outcomes and results

may differ materially from

what we have expressed

or forecast in the forward

-looking statements.

Any differences could result from a variety of factors

and uncertainties, including, but not

limited to, the following:

The impact of public health crises, including pandemics

(such as COVID-19) and epidemics and any

related company or government policies or

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

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

producing countries and the resulting company

Any differences

could result from a variety of factors

and uncertainties, including, but not limited to,

the following:

The impact of public health crises, including pandemics (such as COVID

-19) and epidemics and any related

company or government policies

Global and regional changes in the demand, supply,

prices, differentials or other market

affecting oil and gas, including changes

resulting from a public health crisis or from the imposition

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

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,

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

oil and gas developments, including due to operating

hazards, drilling risks and the inherent

uncertainties in predicting reserves and reservoir

Reductions in reserves replacement rates, whether

as a result of the significant declines in commodity

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.

The potential for insufficient liquidity

or other factors, such as those described

herein, that could impact

our ability to repurchase shares and

declare and pay dividends, whether fixed

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

Unexpected changes in costs or technical requirements

for constructing, modifying or operating E&P

Unsuccessful exploratory drilling

activities or the inability to obtain access to exploratory

Unexpected changes in costs or technical

requirements for constructing,

modifying or operating E&P

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

addressing environmental concerns,

including initiatives addressing

the impact of global climate change or further regulating

hydraulic fracturing, methane

emissions, flaring

or water disposal.

Lack of, or disruptions

in, adequate and reliable transportation

for our crude oil, bitumen, natural gas,

LNG and NGLs.

Inability to timely obtain or maintain permits,

including those necessary for construction, drilling

and/or development, or inability to make capital

expenditures required to maintain compliance

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

Potential disruption or interruption of our operations

due to accidents, extraordinary weather

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.

Inability to timely obtain or maintain

permits, including those necessary for construction, drilling

development, or inability to make

capital expenditures required

to maintain compliance with any

necessary permits or applicable laws or regulations.

ConocoPhillips

Failure to complete definitive

agreements and feasibility studies

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,

supply chain disruptions, civil unrest, political

terrorism, cyber attacks, and

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

relating to crude oil, bitumen, natural gas,

LNG, NGLs and any materials or products (such

aluminum and steel) used in the operation of our

Substantial investment in and development use

of, competing or alternative energy sources, including

as a result of existing or future environmental

including the imposition of trade restrictions or

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

a result of existing or future environmental

rules and regulations.

Liability for remedial actions, including removal

and reclamation obligations, under existing

future environmental regulations and litigation.

Significant operational or investment changes imposed

by existing or future environmental

and regulations, including international agreements

and national or regional legislation and regulatory

and reclamation obligations,

under existing and future

environmental regulations

and litigation.

Significant operational or investment

changes imposed by existing or future

environmental statutes

regulations, including international

agreements and national or regional legislation

and regulatory

measures to limit or reduce GHG emissions.

Liability resulting from litigation, including the

potential for litigation related to the

transaction with

Concho, or our failure to comply with applicable

laws and regulations.

General domestic and international economic and

political developments, including armed

Liability resulting from litigation,

including litigation directly or indirectly

related to the transaction

Concho Resources Inc., or our failure

to comply with applicable laws and regulations.

General domestic and international

economic and political developments, including armed

expropriation of assets;

1 unchanged sentence

policies relating to crude oil, bitumen, natural

LNG and NGLs pricing;

and NGLs pricing;

regulation or taxation;

and other political, economic

or diplomatic

developments.

in the commodity futures markets.

Changes in tax and other laws, regulations (including

alternative energy mandates), or royalty rules

and other political, economic or diplomatic developments.

Volatility in the commodity futures

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

Any limitations on our access to capital or increase

in our cost of capital, including as a result

illiquidity or uncertainty in domestic or international

financial markets or investment sentiment.

Our inability to execute, or delays in the completion,

of any asset dispositions or acquisitions

Potential failure to obtain, or delays in obtaining,

any necessary regulatory approvals for

future asset dispositions or acquisitions,

or that such approvals may require modification

of the transactions or the operation of our remaining

Potential disruption of our operations as a result

of pending or future asset dispositions or acquisitions,

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 or investment

Our inability to execute, or delays

in the completion, of any asset dispositions or acquisitions

Potential failure to obtain,

or delays in obtaining, any necessary

regulatory approvals for

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

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.

asset dispositions that are pending or that we elect

undertake in the future in the manner

and timeframe we currently

anticipate, if 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,

counterparties to satisfy their obligations

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

involuntary, required to mitigate this physical constraint.

Our ability to successfully integrate Concho’s business.

The risk that the expected benefits and cost

reductions associated with the transaction with

may not be fully achieved in a timely manner, or at all.

The risk that we will be unable to retain and hire

key personnel.

Unanticipated difficulties or expenditures relating to

integration with Concho.

Uncertainty as to the long-term value of our common

The diversion of management time on integration-related

The factors generally described in Item 1A—Risk

Factors in this 2020 Annual Report on Form 10-K

and any additional risks described in our other filings

with the SEC.

when due from the government of Venezuela

Our inability to realize anticipated

cost savings and capital expenditure

The inadequacy of storage capacity

for our products, and ensuing curtailments,

whether voluntary or

required to mitigate this physical

The risk that we will be unable to retain

and hire key personnel.

Unanticipated integration

issues relating to the acquisition of assets from

Shell, such as potential

disruptions of our ongoing business and higher than anticipated

integration costs.

Uncertainty as to the long-term value of our

common stock.

The diversion of management time on integration

-related matters.

The factors generally described

Item 1A—Risk Factors

in this 2021 Annual Report on Form 10-K and any

additional risks described in our other filings with the SEC.

ConocoPhillips

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis