ConocoPhillips 2021 10-K Risk Factors Analysis

You should carefully

consider the following risk factors

in addition to the other information

included in this Annual

Report on Form 10-K.

These risk factors are not

the only risks we face.

Our business could also be affected

by

additional risks and uncertainties not currently

known to us or that we currently consider

to be immaterial.

If any

of these risks or other risks that are yet unknown

were to occur,

our business, operating results and

financial

condition, as well as the value of an investment

in our common stock could be adversely

affected.

Risks Related to Our Industry

Our operating results, our ability to execute

on our strategy and the carrying value of our assets

are exposed to

the effects of changing commodity prices.

The oil and gas business is a commodity business.

Our revenues, operating results

and future rate of growth are

highly dependent on the prices we receive for

crude oil, bitumen, natural gas

and NGLs.

Such prices can fluctuate

widely depending upon global events or conditions

that affect supply and demand, most

of which are out of our

control.

In early 2020 global oil demand decreased precipitously

alongside global COVID-19 economic shutdowns.

Although global oil demand and global oil prices improved

through 2021, the global economic recovery

remains

uncertain.

Our industry will continue to be exposed to

the effects of changing commodity prices

given the

volatility in commodity price drivers

and the worldwide political and economic environment

generally,

as well as

continued uncertainty caused by

armed hostilities in various oil-producing regions

around the globe.

Lower crude oil, bitumen, natural gas

and NGL prices may have a material adverse

effect on our revenues,

operating income, cash flows

and liquidity, and

may also affect the amount of dividends we elect

to declare and

pay on our common stock and the amount

of shares we elect to acquire as part of the share repurchase

program

and the timing of such acquisitions.

Lower prices may also limit the amount of reserves we

can produce

economically,

thus adversely affecting our proved

reserves and reserve replacement ratio

and accelerating the

reduction in our existing reserve levels

as we continue production from upstream

fields. Prolonged depressed

crude oil prices may affect certain

decisions related to our operations,

including decisions to reduce capital

investments or curtail operated

production.

Significant reductions in crude oil, bitumen, natural

gas and NGL prices could also require us to

reduce our capital

expenditures, impair the carrying value of our

assets or discontinue the classification of certain

assets as proved

reserves.

In the past three years, we recognized

several impairments, which

are described in

Note 7

.

If commodity

prices decrease relative to their current

levels, and as we continue to optimize

our investments and exercise

capital flexibility,

it is reasonably likely we could

incur future impairments to long-lived assets

used in operations,

investment in nonconsolidated

entities accounted for under the equity

method and unproved properties.

Although it is not reasonably practicable to

quantify the impact of any future impairments

or estimated change to

our unit-of-production

rates at this time, our results

of operations could be adversely affected

as a result.

Our business has been, and will continue to be, adversely affected

by the coronavirus (COVID-19) pandemic.

The COVID-19 pandemic and the measures put in place to

address it have negatively

impacted the global economy,

disrupted global supply chains, reduced global demand for

oil and gas and created significant

volatility and

disruption of financial and commodity markets.

Over the course of the pandemic, public health

officials have

recommended or mandated certain

precautions to mitigate

the spread of COVID-19, including limiting non-

essential gatherings of people, ceasing all non-essential

travel and issuing "social or

physical distancing" guidelines,

"shelter-in-place" orders and

mandatory closures or reductions in capacity

for non-essential businesses.

Although

some of these limitations and mandates have

been relaxed in certain jurisdictions,

others have been reinstated

in

areas that have experienced a resurgence

of COVID-19 cases and there is no guarantee

restrictions will not be

reimposed in the future.

Despite the increased availability

of vaccines in certain jurisdictions, the COVID

-19

pandemic may continue or worsen

during the upcoming months, including as a result of the emergence

of more

infectious variants of the virus,

vaccine hesitancy or increased business and

social activities, which may cause

governmental authorities to reinstate

restrictions.

As a result, the ongoing impact of the COVID-19 pandemic

Risk Factors

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21

ConocoPhillips

2021 10-K

remains uncertain and will depend on the severity,

location and duration of the effects

and spread of the disease,

the effectiveness and duration

of actions taken by authorities to contain

the virus or treat its effect, the availability

and effectiveness of vaccines

or other treatments, and how quickly and

to what extent economic conditions

improve.

See our Human Capital Management section within Item 1 and 2-Business and Properties

, for additional

information on how we have

been impacted and the steps we have

taken in response.

Our business is likely to continue to

be further negatively impacted by the COVID

-19 pandemic.

These impacts

could include but are not limited to:

●

Reduced demand for our products

as a result of reductions in travel

and commerce, whether related to

mandated restrictions or otherwise;

●

Disruptions in our supply chain due in part to scrutiny

or embargoing of shipments from infected

areas or

invocation of force majeure

clauses in commercial contracts

due to restrictions imposed as a result

of the

global response to the pandemic;

●

Failure of third-parties on which we rely,

including our suppliers, contract

manufacturers, contractors,

joint venture partners

and external business partners, to

meet their obligations to the company,

or

significant disruptions in their ability to do so,

which may be caused by their own financial or operational

difficulties or restrictions imposed in response

to the disease outbreak;

●

Reduced workforce productivity

caused by, but

not limited to, illness, travel

restrictions, quarantine, or

government mandates;

●

Increased challenges in retention

of personnel caused by vaccine hesitancy

and the resistance of some in

our workforce to comply with

workplace protocols necessary to ensure

the health and safety of our

workforce and minimize disruptions

to the business, such as vaccine and testing requirements,

or the use

of personal protective equipment; and

●

Voluntary or involuntary

curtailments to support oil prices or alleviate storage

shortages for our products.

Any of these factors, or other cascading

effects of the COVID-19 pandemic that

are not currently foreseeable,

could materially increase our costs,

negatively impact our revenues and

damage our financial condition, results of

operations, cash flows and liquidity position.

Despite the rollout of vaccines, the pandemic continues

to progress

and evolve, and the full extent and

duration of any such impacts cannot

be predicted at this time because of the

sweeping impact of the COVID-19 pandemic on daily life

around the world and a lack of certainty

as to if or when

conditions will return to pre-COVID

levels.

Unless we successfully develop resources, the scope

of our business will decline, resulting in an adverse impact to

our business.

As we produce crude oil and natural

gas from our existing portfolio,

the amount of our remaining reserves

declines.

If we are not successful in replacing the crude oil and

natural gas we produce with

good prospects for

future organic opportunities or through

acquisitions, our business will decline.

In addition, our ability to

successfully develop our reserves is dependent

on a number of factors, including our ability to

obtain and renew

rights to develop and produce hydrocarbons;

our success at reservoir optimization; our ability

to bring long-lead

time, capital intensive projects

to completion on budget and on schedule; and our ability

to efficiently and

profitably operate mature

properties.

If we are not successful in developing the resources

in our portfolio, our

financial condition and results of operations

may be adversely affected.

The exploration and production of oil and gas is a highly comp

etitive industry.

The exploration and production

of crude oil, bitumen, natural gas and NGLs

is a highly competitive business.

We

compete with private, public

and state-owned companies in all

facets of the exploration and

production business,

including to locate and obtain new sources

of supply and to produce crude oil, bitumen, natural

gas and NGLs in an

efficient, cost-effective

manner.

We must compete for

the materials, equipment, services, employees

and other

personnel (including geologists, geophysicists,

engineers and other specialists) necessary to conduct

our business.

Some of our competitors are larger

and have greater resources

than we do, or may have

established strategic

long-

Risk Factors

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ConocoPhillips

2021 10-K

22

term positions or strong governmental

or other relationships in countries

or areas in which we operate, or may

be

willing to incur a higher level of risk than we are willing to

incur to obtain potential sources

of supply.

As a

consequence, we may be at a competitive

disadvantage in certain respects,

such as in accessing the necessary

materials, equipment, services, resources

and personnel.

In addition, we may be at a competitive disadvantage

when competing with state-owned

companies if they are motivated

by political or other factors in making their

business decisions, with less emphasis on financial returns.

If we are not successful in our competition for

new

reserves, our financial condition and results

of operations may be adversely

affected.

Any material change in the factors and assumptions

underlying our estimates of crude oil, bitumen, natural gas

and NGL reserves could impair the quantity and value of those reserves.

Our proved reserve information

included in this annual report represents

management's best estimates

based on

assumptions, as of a specified date, of the volumes

to be recovered from underground

accumulations of crude oil,

bitumen, natural gas and NGLs.

Such volumes cannot be directly measured and the

estimates and underlying

assumptions used by management are subject to

substantial risk and uncertainty.

Any material changes in the

factors and assumptions underlying

our estimates of these items could result

in a material negative impact to the

volume of reserves reported or could

cause us to incur impairment expenses on property

associated with the

production of those reserves.

Future reserve revisions could also

result from changes in, among other things,

governmental regulation.

Our business may be adversely affected by price controls,

government-imposed limitations on production

or

exports of crude oil, bitumen, natural gas and NGLs, or the unavailability of adequate

gathering, processing,

compression, transportation, and pipeline facilities and

equipment for our production of crude oil, bitumen,

natural gas and NGLs.

As discussed herein, our operations

are subject to extensive governmental

regulations.

From time to time,

regulatory agencies have imposed

price controls and limitations

on production by restricting the rate

of flow of

crude oil, bitumen, natural gas and

NGL wells below actual production capacity.

Similarly, in response

to increased

domestic energy costs, circumstances

determined to be in the economic interest

of the country,

or a declared

national emergency,

the U.S. government could restrict

the export of our products which would

adversely impact

our domestic business.

Because legal requirements are frequently

changed and subject to interpretation,

we

cannot predict whether future restrictions

on our business may be enacted or become applicable

to us.

Our ability to sell and deliver the crude oil, bitumen, natural

gas, NGLs and LNG that we produce also

depends on

the availability,

proximity,

and capacity of gathering, processing, compression,

transportation and pipeline facilities

and equipment, as well as any necessary diluents

to prepare our crude oil, bitumen, natural

gas, NGLs and LNG for

transport.

Furthermore, we rely on there being sufficient

facilities and takeaway

capacity to support our ambitions

to reduce routine flaring.

The facilities, equipment and diluents

we rely on may be temporarily

unavailable to us

due to market conditions, extreme

weather events, regulatory

reasons, mechanical reasons or other factors

or

conditions, many of which are beyond

our control.

In addition, in certain newer plays, the capacity

of necessary

facilities, equipment and diluents may

not be sufficient to accommodate production

from existing and new wells,

and construction and permitting delays,

permitting costs and regulatory or

other constraints could limit or delay

the construction, manufacture or other acquisition

of new facilities and equipment.

If any facilities, equipment or

diluents, or any of the transportation

methods and channels that we rely on become unavailable

for any period of

time, we may incur increased costs

to transport our crude oil, bitumen, natural

gas, NGLs and LNG for sale or we

may be forced to curtail our

production of crude oil, bitumen, natural

gas or NGLs.

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23

ConocoPhillips

2021 10-K

Our investments in joint ventures decrease

our ability to manage risk.

We conduct many of our operations

through joint ventures in which we

may share control with our

joint venture

partners.

There is a risk our joint venture participants

may at any time have economic,

business or legal interests

or goals that are inconsistent

with those of the joint venture or us, or our joint

venture partners may be unable

to

meet their economic or other obligations and

we may be required to fulfill those obligations

alone.

Failure by us,

or an entity in which we have a joint venture

interest, to adequately manage

the risks associated with any

operations, acquisitions or dispositions could

have a material adverse

effect on the financial condition or results

of

operations of our joint ventures

and, in turn, our business and operations.

Our operations present hazards and risks that require significant

and continuous oversight.

The scope and nature of our operations

present a variety of significant hazards

and risks, including operational

hazards and risks such as explosions,

fires, product spills, severe weather,

geological events, labor disputes,

geopolitical tensions, armed hostilities, terrorist

or piracy attacks, sabotage,

civil unrest or cyberattacks.

Our

operations are subject to the additional

hazards of pollution, toxic substances

and other environmental hazards

and risks.

Offshore activities may pose incrementally

greater risks because of complex

subsurface conditions such

as higher reservoir pressures, water

depths and metocean conditions.

All such hazards could result in loss of

human life, significant property

and equipment damage, environmental

pollution, impairment of operations,

substantial losses to us and damage to

our reputation.

Our business and operations may be disrupted

if we do not

respond, or are perceived not to

respond, in an appropriate manner to

any of these hazards and risks

or any other

major crisis or if we are unable to efficiently

restore or replace affected

operational components

and capacity.

Further, our

insurance may not be adequate to

compensate us for all resulting

losses, and the cost to obtain

adequate coverage may

increase for us in the future.

Legal and Regulatory Risks

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.

Our business is subject to numerous laws and

regulations relating to the protection

of the environment, which are

expected to continue to have

an increasing impact on our operations.

For a description of the most significant of

these environmental laws and

regulations, see the "Contingencies-Environmental"

and "Contingencies-Climate

Change" sections of Management's

Discussion and Analysis of Financial Condition and Results

of Operations.

These laws and regulations continue

to increase in both number and complexity and

affect our operations

with

respect to, among other things:

●

Permits required in connection with exploration,

drilling, production and other activities, including those

issued by national, subnational, and local authorities;

●

The discharge of pollutants into

the environment;

●

Emissions into the atmosphere, such

as nitrogen oxides, sulfur dioxide, mercury

and GHG emissions,

including methane;

●

Carbon taxes;

●

The handling, use, storage, transportation,

disposal and cleanup of hazardous materials

and hazardous

and nonhazardous wastes

;

●

The dismantlement, abandonment and restoration

of historic properties and facilities at

the end of their

useful lives;

and

●

Exploration and production

activities in certain areas, such as offshore

environments, arctic fields, oil

sands reservoirs and unconventional

plays.

We have incurred and

will continue to incur substantial

capital, operating and maintenance, and

remediation

expenditures as a result of these laws and

regulations.

In addition, to the extent these expenditures

are assumed

by a buyer as a result of a disposition, it may

result in our incurring substantial costs

if the buyer is unable to satisfy

these obligations.

Any failure by us to comply

with existing or future laws, regulations

and other requirements

could result in administrative

or civil penalties, criminal fines, other enforcement

actions or third-party litigation

Risk Factors

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2021 10-K

24

against us.

To the extent

these expenditures, as with all costs,

are not ultimately reflected in

the prices of our

products and services, our business, financial condition, results

of operations and cash flows in future

periods

could be materially adversely affected.

Existing and future laws, regulations and internal initiatives

relating to global climate change, such as

limitations on GHG emissions may impact or limit our business plans,

result in significant expenditures, promote

alternative uses of energy or reduce demand for our products.

Continuing political and social attention

to the issue of global climate change has resulted

in both existing and

pending international agreements

and national, regional or local legislation and regulatory

measures to limit GHG

emissions, such as cap and trade regimes, specific

emission standards, carbon taxes,

restrictive permitting,

increased fuel efficiency standards

and incentives or mandates for renewable

energy.

Although we may support

many of these legislative and regulatory

measures, how and when they are enacted could

result in a material

adverse effect to our

business, financial condition, results of operations

and cash flows in future periods.

For example, in November 2021,

the U.S. Environmental Protection

Agency published a Proposed Rule that would

revise the regulations governing

the emission of GHG and volatile organic compounds

from new oil and gas

production facilities, and emission guidelines

for states to use when revising

Clean Air Act implementation plans to

limit GHG emissions from existing oil and gas

facilities.

Although the company supports the direct federal

regulation of methane from new and existing

sources,

the final form and substance of any regulations

are not

currently known and could result in additional

capital expenditures and compliance,

operating and maintenance

costs, any of which may have

an adverse effect on our business

and results of operations.

Additionally,

in 2021, the U.S. joined the international community at

the 26th Conference of the Parties (COP26).

At the conclusion of COP26, the U.S. and nearly

200 other counties agreed to the Glasgow Climate

Pact,

committing to revisiting and strengthening

their current emissions targets

to 2030 in 2022 and finalizing the

outstanding elements of the Paris

Agreement.

In addition, our operations continue

in countries around the world

which are party to the Paris Agreement.

The implementation of current

agreements and regulatory measures,

as

well as any future agreements

or measures addressing climate change and

GHG emissions, may adversely impact

the demand for our products, impose taxes

on our products or operations or require

us to purchase emission

credits or reduce emission of GHGs from our operations.

As a result, we may experience declines in commodity

prices or incur substantial capital expenditures

and compliance, operating, maintenance

and remediation costs,

any of which may have an

adverse effect on our business

and results of operations.

In September 2021, we announced an improvement

to our Paris-aligned climate risk framework,

whereby we

committed to an improvement

to our targets for reduc

ing our scope 1 and 2 emissions intensity on both a

gross

operated and net equity basis and reaffirmed

our commitment to advocate

for the reduction of scope 3 emissions

through our support for a U.S. carbon

price.

Compliance with, and achievement of,

climate change-related

internal initiatives such as the foregoing

may increase costs, require

us to purchase emission credits, or limit or

impact our business plans.

If we are not successful in select internal initiatives,

we may be adversely affected

and

potentially need to reduce

economic end-of-field life

of certain assets and impair associated

net book value.

Increasing attention to

global climate change has also resulted in pressure

from and upon stockholders,

financial

institutions and/or financial markets

to modify their relationships with oil and gas

companies and to limit

investments and/or funding to

such companies.

For example, Harvard University

announced in September 2021

that it will stop investing

its $42 billion endowment in fossil fuels and will let its current

investments expire without

renewal.

As public pressure continues to

mount, our access to capital on terms we

find favorable (if it is available

at all) may be limited and our costs

may increase,

our reputation could be damaged or our business

and results of

operations may be otherwise adversely

affected.

Furthermore, increasing attention

to global climate change has resulted

in an increased likelihood of governmental

investigations and private

litigation, which could increase our costs

or otherwise adversely affect our business.

Beginning in 2017, cities, counties, governments

and other entities in several states

in the U.S. have filed lawsuits

against oil and gas companies,

including ConocoPhillips, seeking compensatory

damages and equitable relief to

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ConocoPhillips

2021 10-K

abate alleged climate change impacts.

Additional lawsuits with similar allegations are

expected to be filed.

The

amounts claimed by plaintiffs are unspecified

and the legal and factual issues

involved in these cases are

unprecedented.

ConocoPhillips believes these lawsuits

are factually and legally meritless and

are an inappropriate

vehicle to address the challenges associated

with climate change and will vigorously

defend against such lawsuits.

The ultimate outcome and impact to

us cannot be predicted with certainty,

and we could incur substantial

legal

costs associated with defending

these and similar lawsuits in the future.

We could also receive lawsuits

alleging a

failure or lack of diligence to meet our

publicly stated ESG goals, so

called "greenwashing" cases.

In addition, although we design and operate

our business operations to accommodate

expected climatic

conditions, to the extent there are

significant changes in the earth's

climate, such as more severe or frequent

weather conditions in the markets

where we operate or the areas

where our assets reside, we could incur

increased expenses, our operations

and supply chain could be adversely impacted, and

demand for our products

could fall.

For more information on legislation

or precursors for possible regulation

relating to global climate change that

affect or could affect

our operations and a description

of the company's response,

see the "Contingencies-Climate

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

.

Domestic and worldwide political and economic developments

could damage our operations and materially

reduce our profitability and cash flows.

Actions of the U.S., state, local

and foreign governments, through

sanctions, tax and other legislation, executive

order and commercial restrictions,

could reduce our operating profitability

both in the U.S. and abroad.

In certain

locations, restrictions on our operations;

leasing restrictions; special taxes

or tax assessments; and payment

transparency regulations

that could require us to disclose competitively

sensitive information or might

cause us to

violate non-disclosure laws of other countries

have been imposed or proposed by governments

or certain interest

groups.

For example, in 2020 a ballot initiative

known as the Fair Share Act was proposed

in the state of Alaska,

which, if enacted would have increased

the state's

share of production revenues and

required producers to

publicly disclose additional financial information.

Although ultimately defeated,

similar initiatives may be

proposed and may be successful in the future.

In addition, we may face regulatory

changes in the U.S. including,

but not limited to, the enactment of tax

law changes that adversely affect

the fossil fuel industry,

new methane

emissions standards, restrictive

flaring requirements, and more stringent

environmental impact studies

and

reviews.

We also cannot rule out the possibility

of similar regulatory shifts and attendant

cost and market access

implications in other international jurisdictions.

One area subject to significant political and

regulatory activity 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 and national laws and

regulations currently govern or,

in some

hydraulic fracturing

operations, prohibit hydraulic

fracturing in some jurisdictions.

Although hydraulic fracturing

has been conducted safely for

many decades, a number of new laws, regulations

and permitting requirements are

under consideration which could result

in increased costs, operating restrictions,

operational delays or could

limit

the ability to develop oil and natural

gas resources.

Certain jurisdictions in which we operate have

adopted or are

considering regulations that could impose

new or more stringent permitting, disclosure

or other regulatory

requirements on hydraulic

fracturing or other oil and natural gas

operations, including subsurface water

disposal.

In addition, certain interest

groups have also proposed ballot initiatives

and constitutional amendments designed

to restrict oil and natural

gas development generally and hydraulic

fracturing in particular.

In the event that ballot

initiatives, local, state,

or national restrictions or prohibitions are

adopted and result in more stringent

limitations

on the production and development of oil and

natural gas in areas where we

conduct operations, we may

incur

significant costs to comply with

such requirements or may experience delays

or curtailment in the permitting or

pursuit of exploration,

development or production activities.

Such compliance costs and delays,

curtailments,

limitations or prohibitions could have

a material adverse effect

on our business, prospects, results of operations,

financial condition and liquidity.

Risk Factors

ConocoPhillips

2021 10-K

26

The U.S. government can also prevent

or restrict us from doing business in foreign

countries.

These restrictions

and those of foreign governments

have in the past limited our ability to

operate in, or gain access to,

opportunities

in various countries.

Actions by host governments, such

as the expropriation of our oil assets by the Venezuelan

government, have affected

operations significantly in the past

and may continue to do so in the future.

Changes in

domestic and international policies and regulations

may affect our ability to collect payments

such as those

pertaining

to the settlement with Petróleos

de Venezuela, S.A. (PDVSA

)

or the ICSID Award against

the

Government of Venezuela;

or to obtain or maintain licenses or permits,

including those necessary for drilling and

development of wells in various locations.

Similarly, the declaration

of a "climate emergency" could

result in

actions to limit exports of our products and other

restrictions.

Local political and economic factors

in international markets

could have a material adverse

effect on us.

Approximately 38 percent

of our hydrocarbon

production was derived from production

outside the U.S. in 2021,

and 29 percent of our proved reserves,

as of December 31, 2021, were located

outside the U.S.

We are subject to

risks associated with operations

in both domestic and international markets,

including changes in foreign

governmental policies relating

to crude oil, natural gas, bitumen, NGLs

or LNG pricing and taxation, other

political,

economic or diplomatic developments (including

the macro effects of international

trade policies and disputes),

potentially disruptive geopolitical conditions,

and international monetary and currency

rate fluctuations.

Restrictions on production of oil and

gas could increase to the extent

governments view such measures as

a viable

approach for pursuing national

and global energy and climate policies.

In addition, some countries where we

operate lack a fully independent judiciary

system.

This, coupled with changes in foreign law or policy,

results in a

lack of legal certainty that exposes

our operations to increased risks,

including increased difficulty in enforcing

our

agreements in those jurisdictions and increased risks

of adverse actions by local government authorities,

such as

expropriations.

Other Risk Factors Facing

our Business or Operations

We may need additional capital in the

future, and it may not be available on acceptable terms

or at all.

We have historically

relied primarily upon cash generated

by our operations to fund our

operations and strategy;

however,

we have also relied from time to

time on access to the debt and equity capital markets

for funding.

There can be no assurance that additional

debt or equity financing will be available in the future on

acceptable

terms or at all.

In addition, although we anticipate we will be

able to repay our existing

indebtedness when it

matures or in accordance with our stated

plans, there can be no assurance we will be able to

do so.

Our ability to

obtain additional financing or refinance our existing

indebtedness when it matures or in

accordance with our

plans, will be subject to a number of factors,

including market conditions, our

operating performance, investor

sentiment and our ability to incur additional debt

in compliance with agreements governing our then-outstanding

debt.

If we are unable to generate sufficient

funds from operations or raise

additional capital for any reason,

our

business could be adversely affected.

In addition, we are regularly evaluated

by the major rating agencies based on a number of factors,

including our

financial strength and conditions affecting

the oil and gas industry generally.

We and other industry companies

have had their ratings reduced

in the past due to negative commodity

price outlooks.

Any downgrade in our credit

rating or announcement that our credit

rating is under review for possible

downgrade could increase the cost

associated with any additional indebtedness

we incur.

Risk Factors

27

ConocoPhillips

2021 10-K

Our business may be adversely affected by deterioration

in the credit quality of, or defaults under

our contracts

with, third-parties with whom we do business.

The operation of our business requires

us to engage in transactions with

numerous counterparties operating

in a

variety of industries, including other companies

operating in the oil and gas industry.

These counterparties may

default on their obligations to

us as a result of operational failures

or a lack of liquidity,

or for other reasons,

including bankruptcy.

Market speculation about the credit

quality of these counterparties, or their ability

to

continue performing on their existing

obligations, may also exacerbate

any operational difficulties

or liquidity

issues they are experiencing, particularly as it relates

to other companies in the oil and gas industry

as a result of

the volatility in commodity prices.

Any default by any of our

counterparties may result in our

inability to perform

our obligations under agreements we have

made with third-parties or may otherwise adversely

affect our business

or results of operations.

In addition, our rights against any of our counterparties

as a result of a default may not be

adequate to compensate us

for the resulting harm caused or may

not be enforceable at all in some circumstances.

We may also be forced

to incur additional costs as we attempt

to enforce any rights

we have against

a defaulting

counterparty,

which could further adversely impact our results

of operations.

Our ability to execute our capital

return program is subject to certain considerations.

In December 2021, we initiated a three

-tier capital return program

that consists of our ordinary dividend, share

repurchases and a quarterly variable

return of cash (VROC).

Ordinary dividends are authorized and determined

by our Board of Directors in its

sole discretion and depend

upon a number of factors, including:

●

Cash available for distribution;

●

Our results of operations and anticipated

future results of operations;

●

Our financial condition, especially in relation to

the anticipated future capital needs of our

properties;

●

The level of distributions paid by comparable

companies;

●

Our operating expenses; and

●

Other factors our Board of Directors

deems relevant.

VROC distributions are also authorized

and determined by our Board of Directors

in its sole discretion and depend

upon a number of factors, including:

●

The anticipated level of distributions

required to meet our capital returns

commitment;

●

Forward prices;

●

Balance sheet cash;

●

Total

yield; and

●

Other factors our Board of Directors

deems relevant.

We expect to continue

to pay a quarterly ordinary dividend

to our stockholders.

In addition, based on the current

environment, we anticipate

also paying a quarterly VROC to

our shareholders staggered from

the ordinary

dividend payment, resulting in up to

eight cash distributions to shareholders

throughout the year;

however,

the

amount of the VROC is variable and will depend upon the

above factors, and our Board

of Directors may determine

not to pay a VROC in a quarter or may

cease declaring a VROC at any time.

In addition,

our Board of Directors may

reduce our ordinary dividend or cease declaring dividends

at any time, including if it determines that

our net cash

provided by operating activities,

after deducting capital expenditures

and investments, are not sufficient

to pay

our desired levels of dividends to our stockholders

or to pay dividends to our stockholders

at all.

Risk Factors

ConocoPhillips

2021 10-K

28

Additionally, as

of December 31, 2021, $10.9 billion of repurchase authority

remained of the $25 billion share

repurchase program our Board

of Directors had authorized.

Our share repurchase program

does not obligate us to

acquire a specific number of shares during any

period, and our decision to commence, discontinue

or resume

repurchases in any period will depend

on the same factors that our Board

of Directors may consider when

declaring dividends, among others.

In the past we have suspended our share

repurchase program in response

to

market downturns, including as a

result of the oil market downturn

that began in early 2020, and we may do so

again in the future.

Any downward revision

in the amount of our ordinary dividend or VROC or the volume of

shares we purchase

under our share repurchase program

could have an adverse effect

on the market price of our common stock.

There are substantial risks with any

acquisitions or divestitures we have completed

or that we may choose to

undertake.

We regularly review our portfolio

and pursue growth through acquisitions

and seek to divest noncore assets or

businesses.

We may not be able to complete these

transactions on favorable

terms, on a timely basis, or at all.

Even if we do complete such transactions,

our cash flow from operations may

be adversely impacted or otherwise

the transactions may not result in the

benefits anticipated due to various

risks, including, but not limited to (i) the

failure of the acquired assets or businesses

to meet or exceed expected

returns, including risk of impairment; (ii)

the inability to dispose of noncore assets and

businesses on satisfactory terms and conditions;

and (iii) the

discovery of unknown and unforeseen liabilities

or other issues related to any

acquisition for which contractual

protections are inadequate

or we lack insurance or indemnities, including environmental

liabilities, or with regard

to divested assets or businesses, claims by

purchasers to whom we have provided

contractual indemnification.

In addition, we may face difficulties

in integrating the operations,

technologies, products and personnel of any

acquired assets or businesses. For example,

we completed two major acquisitions in

2021, including the

acquisition of Concho in January and the acquisition of the Shell Permian assets

in December.

Combined, these

transactions added approximately

800,000 net acres, thereby significantly

increasing our unconventional

position

and operations in the Permian.

We may still encounter

difficulties integrating the acquired

assets into our

business.

There are a large number of processes,

policies, procedures, operations

and technologies and systems

that must be integrated

in connection with the transactions and the integration

of the acquired assets.

It is

possible that the integration process

could result in the disruption of our ongoing business;

inconsistencies in

standards, controls,

procedures and policies; unexpected integration

issues; higher than expected integration

costs

and an overall post-completion

integration process that

takes longer than originally anticipated.

We have been

and will be required to devote management

attention and resources

to integrating the business

practices and

operations.

Any delays encountered

in the integration process

could have an adverse effect

on our revenues or on

our level of expenses or capital investment

and operating results, which may

adversely affect the value

of our

common stock.

In addition, the actual integration may

result in additional and unforeseen

expenses.

Although we

expect that the strategic benefits,

and additional income, as well as the realization

of other efficiencies related to

the integration of the acquired

assets, may offset incremental

transaction-related costs

over time, if we are not

able to adequately address integration

challenges.

Risk Factors

29

ConocoPhillips

2021 10-K

Our technologies, systems and networks

may be subject to cyberattacks.

Our business, like others within the oil and

gas industry,

has become increasingly dependent on digital

technologies, some of which are managed by third

-party service providers on whom we rely

to help us collect, host

or process information.

Among other activities, we rely on digital technology to

estimate oil and gas reserves,

process and record financial and operating

data, analyze seismic and drilling information

and communicate with

employees and third-parties.

As a result, we face various cybersecurity

threats such as attempts to

gain

unauthorized access to, or control

of, sensitive information

about our operations and our employees, attempts

to

render our data or systems

(or those of third-parties with whom we do business,

including third-party cloud and IT

service providers) corrupted or unusable,

threats to the security of our facilities and infrastructure

as well as those

of third-parties with whom we do business,

including third-party cloud and IT service providers,

and attempted

cyber terrorism.

In addition, computers control

oil and gas production, processing equipment

and distribution systems

globally and

are necessary to deliver our production

to market.

A disruption, failure, or a cyberattack

of these operating

systems, or of the networks

,

software and infrastructure

on which they rely,

many of which are not owned or

operated by us, could damage critical

production, distribution or storage

assets, delay or prevent delivery

to

markets,

make it difficult or impossible to accurately

account for production and settle

transactions, or negatively

impact public health or safety,

economic security, or

national security.

Although we have experienced occasional

cybersecurity incidents, none have had

a material effect on our

business, operations or reputation.

As cyberattacks have

continued

to evolve, we have become subject

to new

government-imposed security requirements

to implement specific mitigation measures

to protect against

ransomware attacks

and other known threats to information

and operations technology.

In response, we must

continually expend additional resources

to continue to modify or enhance our protective

measures or to

investigate and

remediate any vulnerabilities

detected.

Our implementation of reasonable security

procedures

and controls to monitor and mitigate

security threats and to increase security

for our information, facilities

and

infrastructure may result

in increased costs.

Despite our ongoing investments

in security resources, talent and

business practices, we are unable to assure

that any security measures will be completely

effective.

If our systems and infrastructure

were to be breached, damaged or disrupted,

we could be subject to serious

negative consequences, including disruption

of our operations, damage to our reputation,

a loss of counterparty

trust, reimbursement or other costs,

increased compliance costs, litigation

exposure and legal liability or regulatory

fines, penalties or intervention.

In addition, we have exposure to

cybersecurity incidents and the negative

impacts

of such incidents related to our data

and proprietary information housed

on third-party IT systems, including

the

cloud.

Any of these could materially and adversel

y

affect our business, results of operations

or financial condition,

and any of the foregoing can

be exacerbated by a delay

or failure to detect a cybersecurity

incident or the full

extent of such incident notwithstanding

reasonable security procedures and controls.

The prevalence of remote

working during the pandemic has introduced

additional cybersecurity risk.

Although we have business continuity

plans in place, our operations may be adversely

affected by significant

and widespread disruption to our systems

and infrastructure that support

our business.

While we continue to evolve and modify our business

continuity

plans, there can be no assurance that

they will be completely effective

in avoiding disruption and business

impacts.

Further, our

insurance may not be adequate to

compensate us for all resulting

losses, and the cost to obtain

adequate coverage may

increase for us in the future.

ConocoPhillips

2021 10-K

30

Item 1B. Unresolved Staff Comments

None.

Item 3.

Legal Proceedings

We are a defendant

in a number of legal and administrative

proceedings arising in the ordinary course

of business,

including those involving governmental

authorities under federal, state

and local laws regulating the discharge

of

materials into the environment.

While it is not possible to accurately predict

the final outcome of these pending

proceedings, if any one or more of such proceedings

were to be decided adversely to

ConocoPhillips, we expect

there would be no material effect

on our consolidated financial position.

See

Note 11

for a description of such

legal and administrative

proceedings.

Item 4.

Mine Safety Disclosures

Not applicable.

Information about our Executive

Officers

Name

Position Held

Age*

William L. Bullock, Jr.

Executive Vice President and Chief

Financial Officer

57

Kontessa S. Haynes-Welsh

Chief Accounting Officer

47

Ryan M. Lance

Chairman of the Board of Directors

and Chief Executive Officer

59

Timothy A. Leach

Executive Vice President, Lower

48

62

Andrew D. Lundquist

Senior Vice President, Government Affairs

61

Dominic E. Macklon

Executive Vice President, Strategy,

Sustainability and Technology

52

Nicholas G. Olds

Executive Vice President, Global

Operations

52

Kelly B. Rose

Senior Vice President, Legal, General

Counsel

55

Heather G. Sirdashney

Vice President, Human Resources

and Real Estate and Facilities

Services

49

*On February 17, 2022.

There are no family relationships

among any of the officers named above.

Each officer of the company is elected

by the Board of Directors at

its first meeting after the Annual Meeting of Stockholders

and thereafter as

appropriate.

Each officer of the company holds

office from the date of election until the first

meeting of the

directors held after the next Annual

Meeting of Stockholders or until a successor

is elected.

The date of the next

annual meeting is May 10, 2022.

Set forth below is information

about the executive officers.

William L. Bullock, Jr.

was appointed Executive

Vice President and Chief Financial Officer as

of September 2020,

having previously served as President,

Asia Pacific & Middle East since April 2015.

Prior to that, he was Vice

President, Corporate Planning

& Development since May 2012.

31

ConocoPhillips

2021 10-K

Kontessa S. Haynes-Welsh

was appointed Chief Accounting

Officer in March 2021, having previously

served as

Assistant Controller since

January 2020.

Prior to that, she was Manager,

Strategy,

Planning and Portfolio

Management from June 2018 to December 2019.

She became Manager,

Finance & Performance Analysis in

September 2016 and served in that role until

May 2018.

Ms. Haynes-Welsh previously

held the position of

Director,

Lower 48 Strategy & Portfolio

Management from February 2016 to

September 2016.

Ryan M. Lance

was appointed Chairman of the Board of Directors

and Chief Executive Officer in May

2012, having

previously served as Senior Vice President, Exploration

and Production-International since May

Timothy A. Leach

was appointed Executive

Vice President, Lower 48 in January 2021.

Prior to joining

ConocoPhillips, Mr.

Leach served as Chairman and Chief Executive Officer

of Concho Resources Inc., from

its

formation in February 2006, until its

acquisition by ConocoPhillips in January 2021.

Andrew D. Lundquist

was appointed Senior Vice President, Government

Affairs in February 2013.

Prior to that, he

served as managing partner of BlueWater

Strategies LLC, since 2002.

Dominic E. Macklon

was appointed Executive Vice President,

Strategy,

Sustainability and Tec

hnology in September

2021, having previously served as Senior Vice President,

Strategy,

Exploration and Technology

since August 2020.

Prior to that, he served as President, Lower

48 from June 2018 to August 2020, Vice President,

Corporate Planning

& Development from January 2017 to June 2018, and

President, U.K. from September

2015 to January 2017.

Mr.

Macklon previously served as Senior Vice President,

Oil Sands in Canada from July 2012 to September 2015.

Nicholas G. Olds

was appointed Executive

Vice President, Global Operations as

of August 2021,

having previously served as Senior Vice President,

Global Operations since August

Prior to that, he served as

Vice President, Corporate Planning

& Development from June 2018 to August

2020, Vice President, Mid-Continent

Business Unit, Lower 48 from September 2016 to

June 2018, and Vice President, North Slope Operations

and

Development in Alaska from August

2012 to September 2016.

Kelly B. Rose

was appointed Senior Vice President,

Legal, General Counsel in September

Prior to that, she

was a senior partner in the Houston office of an international

law firm, Baker Botts L.L.P.,

where she counseled

clients on corporate and securities matters.

She began her career at the firm in 1991.

Heather G. Sirdashney

was appointed Vice President, Human

Resources and Real Estate

and Facilities Services in

March 2021, having previously

served as Vice President, Human Resources from

January 2019.

Prior to that, she

served in other leadership roles including Human

Resources General Manager,

Human Resources Business Partner

Manager,

Lower 48, and Director of Human Resources

Shared Services.

ConocoPhillips

2021 10-K

32

Part II

Item 5.

Market for Registrant's

Common Equity, Related

Stockholder

Matters and Issuer Purchases of Equity Securities

ConocoPhillips' common stock is traded

on the New York Stock

Exchange, under the symbol "COP."

Cash Dividends Per Share

Dividends

2021

2020

First

$

0.430

0.420

Second

0.430

0.420

Third

0.430

0.420

Fourth

0.460

0.430

Number of Stockholders of Record

at January 31, 2022*

38,099

*In determining the number of stockholders, we consider clearing agencies and security position

listings as one stockholder for each agency

listing.

In December 2021, we announced the addition of a VROC tier to our return

of capital program.

The declaration of

ordinary and VROC dividends are subject to

the discretion and approval of our Board

of Directors.

The Board has

adopted a dividend declaration policy

providing that the declaration of any

dividends will be determined quarterly.

For more information on factors

considered when determining the level of these

distributions

see "Item 1A-Risk

Factors - Our ability to execute our capital return program is subject to certain considerations."

Issuer Purchases of Equity Securities

Millions of Dollars

Approximate Dollar

Shares Purchased

Value of Shares

Average

as Part of Publicly

that May Yet

Be

Total

Number of

Price Paid

Announced Plans

Purchased Under the

Period

Shares Purchased

Per Share

or Programs

Plans or Programs

October 1-31, 2021

6,100,833

$

73.36

6,100,833

$

11,811

November 1-30, 2021

6,367,204

73.42

6,367,204

11,344

December 1-31, 2021

6,751,987

71.65

6,751,987

10,860

19,220,024

$

19,220,024

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

plans.

In late 2016, we initiated our current

share repurchase program,

which has a current total program

authorization

of $25 billion of our common stock.

As of December 31, 2021, we had repurchased $14.1 billion

of shares.

Repurchases are made at management's

discretion, at prevailing

prices, subject to market conditions

and other

factors.

Except as limited by applicable legal

requirements, repurchases

may be increased, decreased or

discontinued at any time without prior notice.

Shares of stock repurchased under

the plan are held as treasury

shares.

For more information

see "Item 1A-Risk Factors - Our ability to execute our capital return program is

subject to certain considerations."

33

ConocoPhillips

2021 10-K

Stock Performance Graph

The following graph shows the cumulative

TSR for ConocoPhillips' common stock

in each of the five years from

December 31, 2016 to December 31, 2021.

The graph also compares the cumulative

total returns for the

same

five-year period with the S&P 500 Index and our

performance peer group consisting

of Chevron, ExxonMobil,

Apache, Marathon Oil Corporation,

Devon, Occidental, Hess, and EOG weighted

according to the respective peer's

stock market capitalization

at the beginning of each annual period.

The comparison assumes $100 was invested

on December 31, 2016, in ConocoPhillips stock, the S&P 500 Index

and ConocoPhillips' peer group and assumes that

all dividends were reinvested.

The cumulative total returns

of

the peer group companies' common stock

do not include the cumulative total return

of ConocoPhillips' common

stock.

The stock price performance included in this graph

is not necessarily indicative of future stock

price

performance.

Management's Discussion and Analysis

ConocoPhillips

2021 10-K

34

Item 7.

Management's Discussion and Analysis of Financial Condition and

Results of Operations

Management's Discussion and Analysis is the company's

analysis of its financial performance and of significant

trends that may affect future performance.

It should be read in conjunction with the financial statements

and

notes, 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,"

"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

with the company's disclosures under the heading:

"CAUTIONARY

STATEMENT

FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS

OF THE PRIVATE

SECURITIES LITIGATION

REFORM ACT OF 1995,"

beginning on page

The terms "earnings" and "loss" as used in Management's

Discussion and Analysis refer to net income (loss)

attributable to ConocoPhillips.

Business Environment and Executive Overview

ConocoPhillips is one of the world's

leading E&P companies based on both production and reserves

with

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; LNG

developments; oil sands assets in Canada; and an

inventory of global conventional

and unconventional exploration

prospects.

Headquartered in Houston, Texas,

at December 31, 2021, we employed approximately

9,900 people

worldwide and had total

assets of $91 billion.

Completed Acquisitions

On January 15, 2021, we completed our acquisition

of Concho Resources Inc. (Concho), an independent

oil and gas

exploration and production

company with operations across

New Mexico and West Texas

in an all-stock

transaction for $13.1 billion.

See Note 3

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 Note 3

See Item 1A "Risk Factors" for

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

Overview

After an unprecedented 2020, the energy

landscape improved throughout

2021 with prices reaching pre-pandemic

levels in the second half of the year;

however,

we expect prices will continue to be cyclical

and volatile.

Our view is

that a successful business strategy

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

environments while also

retaining upside during periods of higher prices.

As such,

we are unhedged, remain highly disciplined

in our

investment decisions and continually

monitor market fundamentals,

including OPEC Plus updates regarding

supply

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

of COVID-

Management's Discussion and Analysis

35

ConocoPhillips

2021 10-K

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.

Total

company production was

1,567 MBOED yielding cash

provided by operating activities

of $17 billion.

We invested

$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

per share,

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.

See Note 5

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

through a

combination of natural and accelerated

maturities.

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

in APLNG

for $1.645 billion, before customary

adjustments,

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

into a

divestiture agreement to sell our

interest in noncore assets within

our Lower 48 segment for $440 million.

These

transactions are expected to

close in the first half of 2022.

For more information on APLNG,

see Note 4

and for

more information on pending dispositions,

see Note 3

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

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

debt.

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.

It

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

from all

three tiers at approximately

$8 billion.

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

Capital Resources and Liquidity

Management's Discussion and Analysis

ConocoPhillips

2021 10-K

36

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;

●

Targeting

a reduction in gross operated

and net equity operational GHG emissions intensity

by 40 to 50

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; and

●

ESG performance factoring into

executive and employee compensation

programs.

To support

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

efforts

across the company's

global

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

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.

Management's Discussion and Analysis

37

ConocoPhillips

2021 10-K

Key Operating and Financial

Summary

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

VROC tiers;

●

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

of 2022;

●

Generated $0.3 billion in disposition proceeds

from noncore sales and entered

into agreements

to sell an

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

Libya;

●

Achieved first production from

GMT2, Malikai Phase 2, SNP Phase 2; completed

Tor II project

and started

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;

●

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,

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

-end 2021; and

●

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

basis.

Business Environment

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

and such

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,

peer

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

price

cycles.

We strive to maintain

our 'A'

-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

return

of capital framework,

which consists of a growing, sustainable

dividend, share repurchases, and

beginning

in 2022, the addition of VROC.

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

$2.4

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

activities.

Our first VROC of $0.20

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

shareholders of record as of January

3, 2022.

Our VROC

will be made at the Board of Director's

discretion, subject to market conditions

and other factors.

See

Note 5

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

considerations."

Management's Discussion and Analysis

ConocoPhillips

2021 10-K

38

●

Disciplined investments.

Our goal is to achieve strong

free cash flow by exercising capital

discipline,

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

o

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

cash flow.

As a result, we must invest

significant capital dollars to

develop newly discovered fields,

maintain existing fields, and construct

pipelines and LNG

facilities.

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,

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

sake.

Our cash allocation priorities call for

the investment of sufficient

capital to sustain production

and provide returns of capital

to shareholders.

o

Control our costs.

Controlling operating and overhead

costs, without compromising safety

or

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

in our

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.

o

Optimize our portfolio.

In 2021, we completed the acquisition of Concho and

Shell's Permian

assets, significantly increasing our unconventional

portfolio with many additional years

of low

cost of supply inventory.

The addition of this highly complementary acreage in the Midland

and

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

Indonesia.

We continue to evaluate

our assets to determine whether they

compete for capital within

our

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 $4

to $5 billion in proceeds by year-end

2023 as part of our ongoing portfolio high-grading

and

optimization efforts.

o

Add to our proved reserve base.

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

fields.

◾

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,

the estimate

of proved reserves also changes.

Generally, our

proved reserves decrease as prices

decline and

increase as prices rise.

Management's Discussion and Analysis

39

ConocoPhillips

2021 10-K

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.

Our

reserve replacement was 377 percent

in 2021, reflecting a net increase from purchases

and sales

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 155 percent.

Our

organic reserve replacement

during the three years ended December 31, 2021, which

excluded a

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

make

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 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

years.

●

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

our business

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.

Our

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.

As an

E&P company,

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

3

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

include:

●

Energy commodity prices.

Our earnings and operating cash flows generally

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

weather-

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

2021 10-K

40

Brent crude oil prices averaged

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

with

$41.68 per barrel in 2020.

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.

OPEC

Plus supply

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

prices.

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.

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

demand for

U.S. 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 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

record high

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

U.S. Gulf Coast market through

rail and pipeline contracts.

Our worldwide annual average

realized price increased 70 percent

from $32.15

per BOE in 2020 to $54.63

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

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.

Although providing significant short

and long-term growth opportunities for

our company,

the

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

prices;

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.

Management's Discussion and Analysis

41

ConocoPhillips

2021 10-K

●

Impairments

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,

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

to its fair value,

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

properties.

For more

information on our impairments,

see

Note 6

and

Note 7

●

Effective tax rate

Our operations are in countries

with different tax rates

and fiscal structures.

Accordingly,

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

operations.

●

Fiscal and regulatory environment

Our operations can be affected

by changing economic, regulatory

and political

environments in the various countries

in which we operate, including civil unrest

or strained

relationships with governments

that may impact our operations or

investments.

These 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.

Outlook

Production and Capital

2022 operating plan capital budget

is $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 investme

nts in several early-stage

low-carbon

opportunities that address end-use emissions.

Production guidance is 1.8 MMBOED in 2022 including Libya

but excluding the impacts from the pending

Indonesia

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:

Alaska; Lower 48; Canada; Europe, Middle

East and North Africa; Asia Pacific; and

Other International.

Corporate and Other represents

income and costs not directly associated

with an operating segment, such as most

interest expense, 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

ConocoPhillips

2021 10-K

42

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

by business segment follows:

Millions of Dollars

Years Ended

December 31

2021

2020

2019

Alaska

$

1,386

(719)

1,520

Lower 48

4,932

(1,122)

436

Canada

458

(326)

279

Europe, Middle East and North Africa

1,167

448

3,170

Asia Pacific

453

962

1,483

Other International

(107)

(64)

263

Corporate and Other

(210)

(1,880)

38

Net income (loss) attributable to

ConocoPhillips

$

8,079

(2,701)

7,189

Net Income (loss) attributable to

ConocoPhillips increased $10.8 billion in 2021.

2021 earnings were positively

impacted by:

●

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

in 2020.

●

Lower exploration expenses

due to:

o

Absence of a 2020 impairment for $648 million after

-tax for the entire carrying value

of

capitalized undeveloped leasehold

costs related to our Alaska

North Slope Gas asset.

o

Lower dry hole expenses.

o

Absence of early cancellation of our 2020 winter exploration

program in Alaska.

o

Absence of unproved property

impairment and dry hole expenses in 2020 for the Kamunsu

East

Field in Malaysia, which is no longer in our development

plans.

●

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

in 2020.

●

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.

See Note 7

These increases in net income (loss) were partly

offset by:

●

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

driven from

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

43

ConocoPhillips

2021 10-K

●

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.

Note 12

Income Statement Analysis

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

by higher

LNG and crude prices, partially offset by a higher

effective tax rate

related to equity method investments

in our

Europe, Middle East and North Africa segment

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

to the absence of a $587 million gain related

to

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

divestiture,

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.

See Note 5

Purchased commodities increased 125 percent

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

and

volumes.

Production and operating expenses

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

volumes.

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

costs,

including mark-to-market impacts of certain

key employee compensation

programs.

Exploration expenses decreased

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

including

an $828 million impairment for the entire

carrying value of capitalized

undeveloped leasehold costs related

to our

Alaska North Slope Gas asset, the early cancellation of our

2020 winter exploration

program in Alaska, and

absence

of unproved property impairment and

dry hole expenses from 2020 for the Kamunsu

East Field in Malaysia.

2021

also saw lower dry hole expenses in Alaska.

Impairments decreased $139 million in 2021, 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 in 2021.

For additional information,

see Note 7

and

Note 13

Taxes

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

g

our income tax provision

and effective tax rate.

Results of Operations

ConocoPhillips

2021 10-K

44

Summary Operating Statistics

2021

2020

2019

Average Net Production

Crude oil (MBD)

Consolidated Operations

816

555

692

Equity affiliates

13

13

13

Total

crude oil

829

568

705

Natural gas liquids (MBD)

Consolidated Operations

134

97

107

Equity affiliates

8

8

8

Total

natural gas liquids

142

105

115

Bitumen (MBD)

69

55

60

Natural gas (MMCFD)

Consolidated Operations

2,109

1,339

1,753

Equity affiliates

1,053

1,055

1,052

Total

natural gas

3,162

2,394

2,805

Total Production

(MBOED)

1,567

1,127

1,348

Dollars Per Unit

Average Sales Prices

Crude oil (per bbl)

Consolidated Operations

$

67.61

39.56

60.98

Equity affiliates

69.45

39.02

61.32

Total

crude oil

67.64

39.54

60.99

Natural gas liquids (per bbl)

Consolidated Operations

31.04

12.90

18.73

Equity affiliates

54.16

32.69

36.70

Total

natural gas liquids

32.45

14.61

20.09

Bitumen (per bbl)

37.52

8.02

31.72

Natural gas (per mcf)

Consolidated Operations

6.00

3.17

4.25

Equity affiliates

5.31

3.71

6.29

Total

natural gas

5.77

3.41

5.03

Millions of Dollars

Worldwide Exploration

Expenses

General and administrative;

geological and geophysical,

lease rental, and other

$

300

374

322

Leasehold impairment

10

868

221

Dry holes

34

215

200

Total

Exploration Expenses

$

344

1,457

743

Results of Operations

45

ConocoPhillips

2021 10-K

We explore for,

produce, transport and market

crude oil, bitumen, natural gas,

LNG and NGLs on a worldwide

basis.

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

terminal and

other eastern export terminals.

●

Improved well performance in

Norway,

Canada, Alaska and China.

The increase in production during 2021 was partly

offset by:

●

Normal field decline.

●

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

2021 10-K

46

Alaska

2021

2020

2019

Net Income (Loss) Attributable

to ConocoPhillips

($MM)

$

1,386

(719)

1,520

Average Net Production

Crude oil (MBD)

178

181

202

Natural gas liquids (MBD)

16

16

15

Natural gas (MMCFD)

16

10

7

Total Production

(MBOED)

197

198

218

Average Sales Prices

Crude oil ($ per bbl)

$

69.87

42.12

64.12

Natural gas ($ per mcf)

2.81

2.91

3.19

The Alaska segment primarily explores for,

produces, transports and markets

crude oil, NGLs and natural gas.

In

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 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

program.

See Note 6

●

Lower dry hole expenses.

Earnings were negatively

impacted by:

●

Higher taxes other than income taxes

primarily due to higher realized crude oil prices.

Production

Average production

decreased 1 MBOED in 2021 compared with 2020, primarily

due to:

●

Normal field decline.

The production decrease was partly

offset by:

●

Absence of curtailments.

●

Improved production at

our Western North Slope assets

as a result of net royalty interest

changes

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

47

ConocoPhillips

2021 10-K

Lower 48

2021

2020

2019

Net Income (Loss) Attributable

to ConocoPhillips

($MM)

$

4,932

(1,122)

436

Average Net Production

Crude oil (MBD)

447

213

266

Natural gas liquids (MBD)*

110

74

81

Natural gas (MMCFD)*

1,340

585

622

Total Production

(MBOED)

780

385

451

Average Sales Prices

Crude oil ($ per bbl)**

$

66.12

35.17

55.30

Natural gas liquids ($ per bbl)

30.63

12.13

16.83

Natural gas ($ per mcf)**

4.38

1.65

2.12

*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

Concho

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.

See Note 12

The Lower 48 segment consists of operations

located in the contiguous U.S. and

the Gulf of Mexico.

During 2021,

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 earnings of $4,932 million in 2021, compared

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

Earnings

were positively impacted by:

●

Higher realized crude oil, NGL and natural

gas prices.

●

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.

and

Note

13

●

Higher gains on dispositions related to

selling our interests in certain noncore

assets.

Earnings were negatively

impacted by:

●

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.

Note 3

and

Note 12

Production

Total

average production

increased 395 MBOED in 2021 compared with 2020, primarily

due to:

●

Higher volumes due to our Concho acquisition.

●

New wells online from our development programs

in Permian, Eagle Ford

and Bakken.

●

Absence of curtailments.

These production increases were partly

offset by:

●

Normal field decline.

Results of Operations

ConocoPhillips

2021 10-K

48

Canada

2021*

2020*

2019**

Net Income (Loss) Attributable

to ConocoPhillips

($MM)

$

458

(326)

279

Average Net Production

Crude oil (MBD)

8

6

1

Natural gas liquids (MBD)

4

2

Bitumen (MBD)

69

55

60

Natural gas (MMCFD)

80

40

9

Total Production

(MBOED)

94

70

63

Average Sales Prices

Crude oil ($ per bbl)

$

56.38

23.57

40.87

Natural gas liquids ($ per bbl)

31.18

5.41

19.87

Bitumen ($ per bbl)

37.52

8.02

31.72

Natural gas ($ per mcf)

2.54

1.21

0.49

*Average sales prices include unutilized transportation costs.

**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. Gulf Coast.

Our Canadian operations consist of the Surmont

oil sands development in Alberta and the liquids-rich Montney

unconventional play in

British Columbia.

In 2021, Canada contributed 8 percent of our

consolidated liquids

production and 4 percent of our consolidated

natural gas production.

Net Income (Loss) Attributable to ConocoPhillips

Canada operations reported

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

Earnings were positively impacted

by:

●

Higher realized bitumen prices and crude

oil prices.

●

After-tax gains

on disposition related to contingent

payments of $246 million in 2021 associated

with the

sale of certain assets to CVE in 2017.

●

Higher sales volumes in our Surmont and Montney

assets.

Earnings were negatively impacted

by:

●

Higher production and operating expenses

primarily due to increased Surmont and Montney

production.

Production

Total

average production

increased 24 MBOED in 2021 compared with 2020.

The production increase was

primarily due to:

●

Improved well performance in

Surmont.

●

New wells online in Montney.

●

Production from our Kelt acquisition

completed in the third quarter of 2020.

●

Absence of curtailments.

Results of Operations

49

ConocoPhillips

2021 10-K

Europe, Middle East and North Africa

2021

2020

2019

Net Income (Loss) Attributable

to ConocoPhillips

($MM)

$

1,167

448

3,170

Consolidated Operations

Average Net Production

Crude oil (MBD)

118

86

138

Natural gas liquids (MBD)

4

4

7

Natural gas (MMCFD)

313

275

478

Total Production

(MBOED)

175

136

224

Average Sales Prices

Crude oil ($ per bbl)

$

68.97

43.30

64.94

Natural gas liquids ($ per bbl)

43.97

23.27

29.37

Natural gas ($ per mcf)

13.27

3.23

4.92

The Europe, Middle East and North Africa

segment consists of operations

principally located in the Norwegian

sector of the North Sea; the Norwegian Sea; Qatar; Libya;

and terminalling operations in the U.K.

In 2021, our

Europe, Middle East and North Africa

operations contributed

12 percent of our consolidated liquids

production

and 14 percent of our consolidated

natural gas production.

Net Income Attributable to ConocoPhillips

The Europe, Middle East and North Africa

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

with

earnings of $448 million in 2020.

Earnings were positively impacted

by:

●

Higher realized natural

gas, crude oil and NGL prices.

●

Higher LNG sales prices, reflected in equity in earnings

of affiliates.

●

Higher sales volumes of crude oil and LNG.

Earnings were negatively

impacted by:

●

Higher taxes.

●

Higher DD&A expenses and production and

operating expenses.

Partly offsetting the increase

in DD&A

expenses were lower rates

from positive reserve revisions.

Consolidated Production

Average consolidated

production increased 39 MBOED in 2021, compared

with 2020.

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

terminal and

other eastern export terminals.

●

Improved well performance in

Norway.

●

New production from Norway

drilling activities, including our Tor

II redevelopment project which

achieved full production in 2021.

These production increases were partly

offset by:

●

Normal field decline.

Results of Operations

ConocoPhillips

2021 10-K

50

Asia Pacific

2021

2020

2019

Net Income (Loss) Attributable

to ConocoPhillips

($MM)

$

453

962

1,483

Consolidated Operations

Average Net Production

Crude oil (MBD)

65

69

85

Natural gas liquids (MBD)

1

4

Natural gas (MMCFD)

360

429

637

Total Production

(MBOED)

125

141

196

Average Sales Prices

Crude oil ($ per bbl)

$

70.36

42.84

65.02

Natural gas liquids ($ per bbl)

33.21

37.85

Natural gas ($ per mcf)

6.56

5.39

5.91

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

natural gas

production.

Net Income Attributable to ConocoPhillips

Asia Pacific reported earnings of $453 million

in 2021, compared with $962 million in 2020.

The decrease in earnings

was mainly due to:

●

An impairment of $688 million after-tax on

our APLNG investment.

Note 4

and

Note 13

●

Absence of a $597 million after-tax gain

related to our Australia

-West divestiture.

●

Absence of sales volumes associated with Australia

-West.

Earnings were positively impacted

by:

●

Higher crude oil and natural gas

prices.

●

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

divestiture.

For additional information related

to this FID bonus, see

Note 3

and

Note 11

Consolidated Production

Average consolidated

production decreased 16 MBOED in 2021, compared

with 2020.

The decrease was primarily

due to:

●

The divestiture of our Australia

-West assets that contributed

18 MBOED in 2020.

●

Normal field decline.

These production decreases were partly

offset by:

●

Development activity at Bohai Bay

in China.

●

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

51

ConocoPhillips

2021 10-K

Other International

2021

2020

2019

Net Income (Loss) Attributable

to ConocoPhillips

($MM)

$

(107)

(64)

263

The Other International segment includes exploration

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

our

exploration program

and announced our intent to pursue

managed exits

from certain areas.

Other International operations

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

loss of $64 million in 2020.

Earnings were negatively

impacted by:

●

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

by:

●

Absence of exploration expenses

associated with dry hole costs and a full impairment of

capitalized

undeveloped leasehold costs in Colombia in the fourth

quarter of 2020.

Corporate and Other

Millions of Dollars

2021

2020

2019

Net Income (Loss) Attributable

to ConocoPhillips

Net interest

$

(801)

(662)

(604)

Corporate general and administrative

expenses

(317)

(200)

(252)

Technology

25

(26)

123

Other

883

(992)

771

$

(210)

(1,880)

38

Net interest consists

of interest and financing expense,

net of interest income and capitalized

interest.

Net

interest expense increased $139

million in 2021 compared with 2020, primarily due to higher

debt balances

assumed due to our Concho acquisition.

See Note 9

Corporate G&A expenses include

compensation programs and

staff costs.

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

See Note 16

Technology includes

our investment in new technologies

or businesses, as well as licensing revenues.

Activities are

focused on both conventional

and tight oil reservoirs, shale gas,

heavy oil, oil sands, enhanced oil recovery as well

as LNG.

Earnings from Technology

increased by $51 million in 2021 compared with 2020,

primarily due to higher

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 segment,

premiums incurred on the early retirement

of debt,

holding gains or losses on equity securities, and

pension

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

2021 10-K

52

Capital Resources and Liquidity

Financial Indicators

Millions of Dollars

Except as Indicated

2021

2020

2019

Net cash provided by operating

activities

$

16,996

4,802

11,104

Cash and cash equivalents

5,028

2,991

5,088

Short-term investments

446

3,609

3,028

Short-term debt

1,200

619

105

Total

debt

19,934

15,369

14,895

Total

equity

45,406

29,849

35,050

Percent of total debt to

capital*

31

%

34

30

Percent of floating-rate

debt to total debt

4

%

7

5

*Capital includes total debt and total equity.

To meet our

short-

and long-term liquidity requirements,

we look to a variety of funding sources,

including cash

generated from operating

activities, proceeds from asset sales,

our commercial paper and credit facility programs

and our ability to sell securities using our shelf registration

statement.

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;

and $1.2

billion for hedging, transaction and restructuring

costs.

In 2021, cash and cash equivalents increased by

$2.0

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

of

liquidity.

We believe current cash

balances and cash generated by

operations, together with access to

external

sources of funds as described below in the "Significant 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

In 2021, cash provided by operating

activities was $17 billion, compared with $4.8 billion

for 2020.

The increase is

primarily due to higher realized commodity

prices and higher sales volumes,

mostly resulting from our acquisition

of Concho.

The increase was partly offset by

the $0.8 billion in settlement of oil and gas hedging

positions

acquired from Concho, and approximately

$0.4 billion of transaction and restructuring

costs.

Our short-

and long-term operating cash flows

are highly dependent upon prices for crude oil, bitumen,

natural

gas, LNG and NGLs.

Prices and margins in our industry have historically

been volatile and are driven by market

conditions over which we have no

control.

Absent other mitigating factors,

as these prices and margins fluctuate,

we would expect a corresponding change

in our operating cash flows.

The level of absolute production volumes,

as well as product and location mix, impacts our cash

flows.

Full-year

production averaged

1,567 MBOED in 2021.

Full-year production excluding

Libya averaged 1,527

MBOED.

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 28 MBOED or

2 percent.

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 and

variable-royalty contracts;

acquisition and disposition of fields; field production decline rates;

new technologies;

operating efficiencies; timing of startups

and major turnarounds; political instability;

weather-related disruptions;

Capital Resources and Liquidity

53

ConocoPhillips

2021 10-K

and the addition of proved reserves through

exploratory success and their timely and cost

-effective

development.

While we actively manage these factors,

production levels can cause variability

in cash flows,

although generally this variability has

not been as significant as that caused by commodity prices.

To maintain

or grow our production volumes 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.

Reserve replacement

represents the net change in proved

reserves, net of production, divided by our current

year production.

For

information on proved

reserves, including both developed and undeveloped

reserves,

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

business."

As discussed in the "Critical Accounting Estimates"

section, engineering estimates of proved

reserves are

imprecise; therefore, reserves

may be revised upward or

downward each year due to the impact of changes

in

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 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,

see the

"Capital Expenditures and Investments"

section.

In December 2021, we completed our acquisition

of Shell's assets in

the Delaware Basin for cash consideration

of

approximately $8.7 billion after

customary adjustments.

We funded this transaction with cash

on hand.

We

completed our acquisition of Concho on January 15, 2021.

The assets acquired in the transaction included

$382

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.

See Note 3.

In 2021, we announced a disposition target

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

Only

proceeds from transactions announced

or initiated in the third quarter of 2021 or later

will be counted toward this

target.

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.

To date,

we have achieved $0.3 billion from

the

sale of noncore assets in our Lower 48 segment.

Total

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

See Note 3.

In May 2021, we announced

and began a paced monetization of our

investment in CVE with the plan to

direct proceeds toward

our existing

share repurchase program.

We expect to fully dispose

of our CVE common shares by early 2022, however,

the

sales pace will be guided by market conditions,

and we retain discretion to

adjust accordingly.

See Note 5.

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.

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

U.K.

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

interest in the Greater

Sunrise Fields.

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 in highly liquid

instruments with maturities within the year.

Funds we consider available to maintain

resiliency in longer term

Capital Resources and Liquidity

ConocoPhillips

2021 10-K

54

price downturns and to capture opportunities

outside a given operating plan may

be invested in instruments

with

maturities greater than one year.

See Note 12

Financing Activities

We have a revolving

credit facility totaling $6.0 billion, expiring

in May 2023.

Our revolving credit facility

may be

used for direct bank borrowings,

the issuance of letters of credit totaling

up to $500 million, or as support for our

commercial paper program.

The revolving credit facility is broadly

syndicated among financial institutions

and

does not contain any material

adverse change provisions or any

covenants requiring maintenance of specified

financial ratios or credit ratings.

The facility agreement contains

a cross-default provision relating

to the failure to

pay principal or interest

on other debt obligations of $200 million or more by

ConocoPhillips, or any of its

consolidated subsidiaries.

The amount of the facility is not subject to the 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,

amounts.

The

agreement also contains early termination

rights if our current directors

or their approved successors

cease to be a

majority of the Board of Directors.

The revolving credit facility supports

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.

Commercial paper maturities are

generally limited to 90 days.

With no commercial paper outstanding

and no direct borrowings or letters

of credit,

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,

we

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

and

efficient capital structure.

Note 9

and

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

for the E&P industry to 'Moderately

High' from

'Intermediate' based on a view of increasing

risks from the energy transition,

price volatility,

and weaker

profitability.

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

of our long-term debt from "A"

to "A

-" with a

"stable" outlook and affirmed

this rating in November 2021.

In October 2021, Moody's affirmed its "A3"

rating of

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 the

commercial paper markets.

If our credit rating were to deteriorate

to a level prohibiting us from accessing

the

commercial paper market, we

would still be able to access funds under our revolving

credit facility.

Certain of our project-related

contracts, commercial contracts

and derivative instruments contain

provisions

requiring us to post collateral.

Many of these contracts and instruments

permit us to post either cash or letters

of

credit as collateral.

At December 31, 2021 and 2020, we had direct

bank letters of credit of $337 million and

$249

million, respectively,

which secured performance obligations

related to various purchase

commitments incident to

the ordinary conduct of business.

In the event of credit ratings downgrades,

we may be required to post

additional

letters of credit.

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

55

ConocoPhillips

2021 10-K

Capital Requirements

For information about our capital

expenditures and investments,

see the "Capital Expenditures and Investments"

section.

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.

See Note 9

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

and

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

activities

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

tiers.

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. This

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

$1.34 per

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

14, 2022.

On January 14,

2022, we paid the first VROC payment

of $0.20 per share to shareholders

of record as of January 3, 2022.

On

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

payable on April 14, 2022, to stockholders

of record at

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

of $25

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

of capital

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

commodities.

Purchase

obligations of $5.3 billion are related

to market-based contracts

for commodity product purchases

with third

parties.

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

2021 10-K

56

Capital Expenditures and Investments

Millions of Dollars

2021

2020

2019

Alaska

$

982

1,038

1,513

Lower 48

3,129

1,881

3,394

Canada

203

651

368

Europe, Middle East and North Africa

534

600

708

Asia Pacific

390

384

584

Other International

33

121

8

Corporate and Other

53

40

61

Capital Program*

$

5,324

4,715

6,636

• 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

Canada.

●

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

in several

early-stage low-carbon

opportunities that address end-use emissions.

Capital Resources and Liquidity

57

ConocoPhillips

2021 10-K

Guarantor Summarized Financial

Information

We have various

cross guarantees among ConocoPhillips,

ConocoPhillips Company,

and Burlington Resources LLC

with respect to publicly held debt securities.

ConocoPhillips Company is 100 percent

owned by ConocoPhillips.

Burlington Resources LLC is

100 percent owned by ConocoPhillips Company.

ConocoPhillips and/or ConocoPhillips

Company have fully and unconditionally

guaranteed the payment obligations

of Burlington Resources LLC with

respect to its publicly held debt securities.

Similarly, ConocoPhillips

has fully and unconditionally guaranteed the

payment obligations of ConocoPhillips

Company with respect to its publicly held

debt securities.

In addition,

ConocoPhillips Company has fully and unconditionally

guaranteed the payment obligations

of ConocoPhillips with

respect to its publicly held debt securities.

All guarantees are joint and

several.

The following tables present summarized

financial information for

the Obligor Group, as defined below:

●

The Obligor Group will reflect guarantors

and issuers of guaranteed securities consisting

of

ConocoPhillips, ConocoPhillips Company

and Burlington Resources LLC.

●

Consolidating adjustments for elimination

of investments in and transactions

between the collective

guarantors and issuers

of guaranteed securities are reflected

in the balances of the summarized financial

information.

●

Non-Obligated Subsidiaries are exclud

ed from this presentation.

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

Concho's publicly traded

debt of

approximately $3.9 billion in aggregate

principal amount, which was recorded

at 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

for

new debt issued by ConocoPhillips.

The new debt issued in the exchange is fully and

unconditionally guaranteed

by ConocoPhillips Company.

Both the guarantor and issuer of the exchange

debt is reflected within the Obligor

Group presented here.

and

Note 9

Transactions

and balances reflecting activity between the Obligors

and Non-Obligated Subsidiaries

are presented

separately below:

Summarized Income Statement

Data

Millions of Dollars

2021

Revenues and Other Income

$

30,457

Income (loss) before income taxes*

8,017

Net income (loss)

8,079

Net Income (Loss) Attributable

to ConocoPhillips

8,079

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

Summarized Balance Sheet Data

Millions of Dollars

December 31, 2021

Current assets

$

7,689

Amounts due from Non-Obligated Subsidiaries, current

1,927

Noncurrent assets

69,841

Amounts due from Non-Obligated Subsidiaries, noncurrent

7,281

Current liabilities

8,005

Amounts due to Non-Obligated Subsidiaries,

current

3,477

Noncurrent liabilities

30,677

Amounts due to Non-Obligated Subsidiaries,

noncurrent

13,007

Capital Resources and Liquidity

ConocoPhillips

2021 10-K

58

Contingencies

We are subject to legal proceedings,

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

We accrue

for losses associated with legal

claims when such losses are considered probable

and the amounts can be

reasonably estimated.

See "Critical Accounting Estimates"

and

for information on contingencies.

Legal and Tax

Matters

We are subject to various

lawsuits and claims, including but not limited to matters

involving oil and gas royalty

and

severance tax payments,

gas measurement and valuation

methods, contract disputes,

environmental damages,

climate change, personal injury,

and property damage.

Our primary exposures for such matters

relate to alleged

royalty and tax underpayments

on certain federal, state

and privately owned properties,

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

mediation.

Based on

professional judgment and experience

in using these litigation management

tools and available information

about

current developments in all our cases,

our legal organization regularly

assesses the adequacy of current accruals

and determines if an adjustment of existing

accruals, or establishment of new accruals, is

required.

See Note 17

Environmental

We are subject to the same numerous

international, federal,

state, and local environmental

laws and regulations

as other companies in our industry.

The most significant of these environmental

laws and regulations include,

among others, the:

●

U.S. Federal Clean Air Act, which governs

air emissions.

●

U.S. Federal Clean Water

Act, which governs discharges

to water bodies.

●

European Union Regulation for

Registration, Evaluation,

Authorization and Restriction of Chemicals

(REACH).

●

U.S. 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.

●

U.S. Federal Resource

Conservation and Recovery

Act (RCRA), which governs the treatment,

storage, and

disposal of solid waste.

●

U.S. 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

of oil into

navigable waters

of the U.S.

●

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 departments.

●

U.S. Federal Safe Drinking

Water Act, which governs

the disposal of wastewater

in underground injection

wells.

●

U.S. 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

Emissions Trading Scheme.

Capital Resources and Liquidity

59

ConocoPhillips

2021 10-K

These laws and their implementing regulations

set limits on emissions and, in the case of discharges

to water,

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.

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

laws and

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

nor easily

determinable as new standards,

such as air emission standards and water

quality standards, continue to

evolve.

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 in the U.S. and

in other

countries in which we operate.

Notable areas of potential impacts include

air emission compliance and

remediation obligations in the U.S.

and Canada.

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

fracturing currently

prohibited in some jurisdictions.

Although hydraulic fracturing has

been conducted for many decades,

a number of

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

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

investments.

We have adopted

operating

principles that incorporate

established industry standards

designed to meet or exceed government

requirements.

Our practices continually evolve

as technology improves and regulations

change.

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

and state

environmental agencies alleging

that we are a potentially responsible

party under CERCLA or an equivalent state

statute.

On occasion, we also have been made a party to

cost recovery litigation by

those agencies or by private

parties.

These requests, notices and lawsuits

assert potential liability for remediation

costs at various sites that

typically are not owned by us, but allegedly contain

wastes attributable to

our past operations.

As of

December 31, 2021, there were 15 sites around

the U.S. in which we were identified as a

potentially responsible

party under CERCLA and comparable state

laws.

Capital Resources and Liquidity

ConocoPhillips

2021 10-K

60

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

responsible

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,

our share of liability has not increased materially.

Many of the sites at

which we are potentially responsible

are still under investigation

by the EPA

or the state agencies concerned.

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 or attain 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 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 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

or

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 subject of CERCLA, RCRA,

or other agency enforcement activities.

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.

If applicable, we accrue receivables for probable

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 policies,

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, 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. and Canada.

We expect to incur a

substantial amount of these expenditures

within the next 30 years.

Notwithstanding any of the foregoing,

and as with other companies engaged in similar businesses,

environmental

costs and liabilities are inherent

concerns in our operations and products,

and there can be no assurance that

material costs and liabilities will not be incurred.

However,

we currently do not expect any material

adverse effect

upon our results of operations or financial position

as a result of compliance with current environmental

laws and

regulations.

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

and

for information

on environmental litigatio

n.

Capital Resources and Liquidity

61

ConocoPhillips

2021 10-K

Climate Change

Continuing political and social attention

to the issue of global climate change has resulted

in a broad range of

proposed or promulgated

state, national and international

laws focusing on GHG reduction.

These proposed or

promulgated laws apply

or could apply in countries where we have

interests or may have

interests in the future.

Laws in this field continue to evolve,

and while it is not possible to accurately estimate

either a timetable for

implementation or our future compliance costs

relating to implementation, such

laws, if enacted, could have a

material impact on our results of operations

and financial condition.

Examples of legislation and precursors

for

possible regulation that do or could affect

our operations include:

●

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

).

●

U.K. Emissions Trading

Scheme, the program with which the U.K. has

replaced the ETS.

Our cost of

compliance with the U.K. ETS in 2021 was approximately

$2.8 million (net share 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 2021 was

approximately $1

million (net share before-tax)

●

The U.S. Supreme Court decision in Massachusetts

v. EPA,

549 U.S. 497, 127 S.Ct. 1438 (2007), confirmed

that the EPA

has the authority to regulate carbon dioxide

as an "air pollutant" under the Federal Clean Air

Act.

●

The U.S. EPA's

announcement on March 29, 2010 (published as "Interpretation

of Regulations that

Determine Pollutants Covered

by Clean Air Act Permitting Programs,"

75 Fed. Reg. 17004 (April 2, 2010)),

and the EPA's

and U.S. Department of Transportation's

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

that triggers regulation of GHGs under

the Clean Air Act, may trigger more climate-based

claims for

damages, and may result in longer agency review

time for development projects.

●

The U.S. EPA's

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.

●

The U.S. government has announced

on September 17, 2021 the Global Methane Pledge,

a global

initiative to reduce global methane emissions

by at least 30 percent from 2020 levels

by 2030.

●

Carbon taxes in certain jurisdictions.

Our cost of compliance with Norwegian carbon legislation

in 2021

were fees of approximately

$35 million (net share before

-tax).

We also incur a carbon tax for

emissions

from fossil fuel combustion in our

British Columbia and Alberta operations in Canada,

totaling

approximately $5.7 million (net

share before-tax).

●

The agreement reached in Paris

in December 2015 at the 21

st

Conference of the Parties to

the United

Nations Framework Convention

on Climate Change, setting out a process

for achieving global emission

reductions.

The new administration has recommitted

the United States to the Paris

Agreement, and a

significant number of U.S. state

and local governments and major corporations

headquartered in the U.S.

have also announced related commitments.

Accordingly,

the U.S. 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

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 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

2021 10-K

62

Compliance with changes in laws and regulations

that create a GHG tax, emission trading

scheme or GHG

reduction policies could significantly increase

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.

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

regulation.

●

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

system or a tax on emissions)

or regulation.

●

The price placed on GHG emissions (either by the market

or through a tax).

●

The GHG reductions required.

●

The price and availability of offsets.

●

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,

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.

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

and

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

Register.

The risks addressed in our Climate Change Action

Plan fall into four broad

categories:

●

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 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

we consume.

●

Scope 3 emissions are indirect emissions from

sources that we neither own nor control.

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63

ConocoPhillips

2021 10-K

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

and

production business through the energy transition.

Given the uncertainties remaining about

how the energy

transition will evolve, the strategy

aims to be robust across a range

of potential future outcomes.

The strategy is comprised of four

pillars:

●

Targets

:

Our target framework

consists of a hierarchy

of targets, from a long-term ambition

that sets the

direction and aim of the strategy,

to a medium-term performance target

for GHG emissions intensity,

to

shorter-term targets for

flaring and methane intensity reductions.

These performance targets are

supported by lower-level internal

business unit goals to enable the company to

achieve the company-

wide targets.

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 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 technology.

●

Portfolio choices: Our corporate

authorization process requires

all qualifying projects to include a GHG

price in their project approval economics.

Different GHG prices are used

depending on the region or

jurisdiction.

Projects in jurisdictions with existing GHG pricing regimes

incorporate the existing

GHG price

and forecast into

their economics.

Projects where no existing GHG pricing regime

exists utilize a scenario

forecast from our internally

consistent World

Energy Model.

In this way,

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 risk.

We are a Founding Member of the

Climate Leadership Council (CLC), an international

policy institute founded in collaboration

with business

and environmental interests

to develop a carbon dividend plan.

Participation in the CLC provides

another

opportunity for ongoing dialogue about carbon

pricing and framing the issues in alignment with our

public

policy principles.

We also belong to and fund Americans For

Carbon Dividends, the education and

advocacy branch of the CLC.

ConocoPhillips

2021 10-K

64

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

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

used.

These

critical accounting estimates are

discussed with the Audit and Finance Committee of the Board

of Directors at least

annually.

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

change.

Oil and Gas Accounting

Accounting for oil and gas activity

is subject to special accounting rules unique to the oil

and gas industry.

The

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.

However,

leasehold acquisition costs and exploratory

well

costs are capitalized

on the balance sheet pending determination of whether

proved oil and gas reserves

have

been recognized.

Property Acquisition Costs

At year-end 2021, we held $9.3 billion

of net capitalized unproved

property costs which consisted

primarily of

individually significant and pooled leaseholds, mineral

rights held in perpetuity by title ownership,

exploratory

wells currently being drilled, and to a lesser

extent, suspended exploratory

wells and capitalized interest.

This

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

in 9 major

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 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,

including estimates of future expirations,

and pools that leasehold information with others

in similar geographic

areas.

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 impairment charge that is

reported in exploration expense.

This judgmental probability percentage

is

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

expense is

adjusted prospectively.

Exploratory Costs

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

to

justify development.

65

ConocoPhillips

2021 10-K

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

of suspended well costs on the expectation

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 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 been obtained, the projects

are moved into the

development phase, and the oil and gas

reserves are designated as proved

reserves.

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,

see Note 6

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 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 of "proved"

reserve estimates due to the importance

of these estimates to better

understand the perceived value

and future

cash flows of a company's

operations.

There are several authoritative

guidelines regarding the engineering criteria

that must be met before estimated

reserves can be designated as "proved."

Our geosciences and reservoir

engineering organization has

policies and procedures in place consistent

with these authoritative guidelines.

We

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

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 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

rise.

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; recoverable

operating expenses; and capital

costs.

If costs remain stable, reserve quantities

attributable to recovery of costs

will change inversely to changes

in commodity prices.

We would expect reserves

from these contracts to

decrease

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

calculation

was approximately $52 billion

and the DD&A recorded on these assets in

2021 was approximately $7.0 billion.

The

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

2021 10-K

66

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

on

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

estimates.

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

time of the

acquisition.

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.

Impairments

Long-lived assets used in operations

are assessed for impairment whenever changes

in facts and circumstances

indicate a possible significant deterioration

in the future cash flows expected

to be generated by an

asset group.

If

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

plans.

If the sum of the

undiscounted cash flows before

income-taxes is less than

the carrying value of the asset group, the carrying

value

is written down to estimated fair

value and reported as an impairment

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 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

are based on

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.

Note 6

and

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 fair

value.

When

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 4

67

ConocoPhillips

2021 10-K

Asset Retirement Obligations

and Environmental Costs

Under various contracts, permits

and regulations, we have material

legal obligations to remove

tangible

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 gas platforms

around the world, as well as oil and gas

production facilities and pipelines in Alaska.

Fair value is estimated using

a

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.

Most of

these removal obligations are

many years, or decades,

in the future and the contracts and regulations

often have

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, 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.

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 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

projects.

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 that may be required,

and the determination of our

liability in proportion to that of other responsible

parties.

See Note 8

Projected Benefit Obligations

The actuarial determination of projected benefit

obligations and company

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,

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 projected benefit

obligations and company

contribution requirements.

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.

A 100 basis-point decrease

in the discount rate assumption

would increase projected benefit obligations

by $1.0 billion.

Benefit expense is

sensitive to the discount rate

and return on plan assets assumptions.

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

cash flows

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 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

to predict.

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,

we could

recognize a curtailment gain

or loss.

See Note 16

ConocoPhillips

2021 10-K

68

Contingencies

A number of claims and lawsuits are made against

the company arising in the ordinary course

of business.

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

to the probability of additional losses and potential

exposure.

However,

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 of liability

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

processes.

For additional information on

contingent liabilities, see the "Contingencies"

section within "Capital Resources and

Liquidity" and

Income Taxes

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

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.

In assessing the need for adjustments

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

feasible.

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

valuation allowances, we weight

the evidence based on

objectivity.

Numerous judgments and assumptions are

inherent in the determination of future taxable

income,

including factors such as future operating

conditions and the assessment of the effects

of foreign taxes

on our U.S.

federal income taxes

(particularly as related to prevai

ling oil and gas prices).

See Note 17

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 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

and

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

17

regarding discussion of critical accounting

estimates on deferred

tax valuation allowances.

69

ConocoPhillips

2021 10-K

Cautionary Statement for the Purposes of the "Safe Harbor" Provisions of the

Private Securities Litigation Reform Act

of 1995

This report includes forward-looking statements

within the meaning of Section 27A of the Securities Act of 1933

and Section 21E of the Securities Exchange Act of 1934.

All statements other than

statements of historical

fact

included or incorporated by

reference in this report, including, without

limitation, statements

regarding our future

financial position, business strategy,

budgets, projected revenues,

projected costs and plans, objectives

of

management for future 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

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

general.

We caution you these

statements are not guarantees

of future

performance as they involve

assumptions that, while made in good faith, may

prove to be incorrect, and involve

risks and uncertainties we cannot predict.

In addition, we based many of these forward

-looking statements on

assumptions about future events

that may prove to be inaccurate.

Accordingly,

our actual outcomes and results

may differ materially from

what we have expressed

or forecast in the forward

-looking statements.

Any differences

could result from a variety of factors

and uncertainties, including, but not limited to,

the following:

●

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

-19) and epidemics and any related

company or government policies

or actions.

●

Global and regional changes in the demand, supply,

prices, differentials or other market

conditions

affecting oil and gas, including changes

resulting from a public health crisis or from the imposition

or

lifting of crude oil production quotas or other actions

that might be imposed by OPEC and other producing

countries and the resulting company

or third-party actions in response to such changes.

●

Fluctuations in crude oil, bitumen, natural gas,

LNG and NGLs prices, including a prolonged decline in

these prices relative to historical

or future expected levels.

●

The impact of significant declines in prices for crude

oil, bitumen, natural gas, LNG and

NGLs, which may

result in recognition of impairment charges

on our long-lived assets, leaseholds and nonconsolidated

equity investments.

●

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

or variable.

●

Potential failures or delays

in achieving expected reserve or production

levels from existing and future oil

and gas developments, including due to

operating hazards, drilling risks

and the inherent uncertainties in

predicting reserves and reservoir performance.

●

Reductions in reserves replacement rates,

whether as a result of the significant declines in commodity

prices or otherwise.

●

Unsuccessful exploratory drilling

activities or the inability to obtain access to exploratory

acreage.

●

Unexpected changes in costs or technical

requirements for constructing,

modifying or operating E&P

facilities.

●

Legislative and regulatory initiatives

addressing environmental concerns,

including initiatives addressing

the impact of global climate change or further regulating

hydraulic fracturing, methane

emissions, flaring

or water disposal.

●

Lack of, or disruptions

in, adequate and reliable transportation

for our crude oil, bitumen, natural gas,

LNG and NGLs.

●

Inability to timely obtain or maintain

permits, including those necessary for construction, drilling

and/or

development, or inability to make

capital expenditures required

to maintain compliance with any

necessary permits or applicable laws or regulations.

ConocoPhillips

2021 10-K

70

●

Failure to complete definitive

agreements and feasibility studies

for,

and to complete construction of,

announced and future E&P and LNG development in a timely

manner (if at all) or on budget.

●

Potential disruption or interruption

of our operations due to accidents, extraordinary

weather events,

supply chain disruptions, civil unrest, political

events, war,

terrorism, cyber attacks, and

information

technology failures, constraints

or disruptions.

●

Changes in international monetary

conditions and foreign currency exchange

rate fluctuations.

●

Changes in international trade relationships,

including the imposition of trade restrictions or

tariffs

relating to crude oil, bitumen, natural

gas, LNG, NGLs and any materials or products

(such as aluminum

and steel) used in the operation of our business.

●

Substantial investment

in and development use of, competing

or alternative energy sources, including

as

a result of existing or future environmental

rules and regulations.

●

Liability for remedial actions, including removal

and reclamation obligations,

under existing and future

environmental regulations

and litigation.

●

Significant operational or investment

changes imposed by existing or future

environmental statutes

and

regulations, including international

agreements and national or regional legislation

and regulatory

measures to limit or reduce GHG emissions.

●

Liability resulting from litigation,

including litigation directly or indirectly

related to the transaction

with

Concho Resources Inc., or our failure

to comply with applicable laws and regulations.

●

General domestic and international

economic and political developments, including armed

hostilities;

expropriation of assets; changes in governmental

policies relating to crude oil, bitumen, natural

gas, LNG

and NGLs pricing; regulation or taxation;

and other political, economic or diplomatic developments.

●

Volatility in the commodity futures

markets.

●

Changes in tax and other laws, regulations

(including alternative energy mandates),

or royalty rules

applicable to our business.

●

Competition and consolidation in the oil and gas

E&P industry.

●

Any limitations on our access to capital

or increase in our cost of capital, including

as a result of illiquidity

or uncertainty in domestic or international

financial markets or investment

sentiment.

●

Our inability to execute, or delays

in the completion, of any asset dispositions or acquisitions

we elect to

pursue.

●

Potential failure to obtain,

or delays in obtaining, any necessary

regulatory approvals for

pending or

future asset dispositions or acquisitions, or that such

approvals may require modification

to the terms of

the transactions or the operation

of our remaining business.

●

Potential disruption of our operations

as a result of pending or future asset dispositions or acquisitions,

including the diversion of management time and

attention.

●

Our inability to deploy the net proceeds from any

asset dispositions that are pending or that we elect

to

undertake in the future in the manner

and timeframe we currently

anticipate, if at all.

●

The operation and financing of our joint ventures.

●

The ability of our customers and other contractual

counterparties to satisfy their obligations

to us,

including our ability to collect payments

when due from the government of Venezuela

or PDVSA.

●

Our inability to realize anticipated

cost savings and capital expenditure

reductions.

●

The inadequacy of storage capacity

for our products, and ensuing curtailments,

whether voluntary or

involuntary,

required to mitigate this physical

constraint.

●

The risk 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

in

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.

71

ConocoPhillips

2021 10-K

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Financial Instrument Market Risk

We and certain of our subsidiaries hold

and issue derivative contracts

and financial instruments that expose our

cash flows or earnings to changes in commodity prices,

foreign currency exchange

rates or interest

rates.

We may

use financial and commodity-based derivative

contracts to manage the risks

produced by changes in the prices of

natural gas, crude oil and related

products; fluctuations in interest

rates and foreign currency

exchange rates; or to

capture market opportunities.

Our use of derivative instruments

is governed by an "Authority

Limitations" document approved

by our Board of

Directors that prohibits

the use of highly leveraged derivatives

or derivative instruments without

sufficient

liquidity.

The Authority Limitations document also establishes

the Value at Risk (VaR)

limits for the company,

and

compliance with these limits is monitored daily.

The Executive Vice President and Chief Financial

Officer, who

reports to the Chief Executive

Officer, monitors

commodity price risk and risks resulting from

foreign currency

exchange rates and

interest rates.

The Commercial organization

manages our commercial marketing, optimizes

our commodity flows and positions, and monitors

risks.

Commodity Price Risk

Our Commercial organization

uses futures, forwards, swaps

and options in various markets

to accomplish the

following objectives:

●

Meet customer needs.

Consistent with our policy to generally

remain exposed to market

prices, we use

swap contracts to convert

fixed-price sales contracts, which

are often requested by natural

gas

consumers, to floating market

prices.

●

Enable us to use market knowledge to

capture opportunities such as moving physical

commodities to

more profitable locations and storing

commodities to capture seasonal or time premiums.

We may use

derivatives to optimize

these activities.

We use a VaR

model to estimate the loss in fair

value that could potentially result

on a single day from the effect of

adverse changes in market

conditions on the derivative financial instruments

and derivative commodity

instruments we hold or issue, including commodity

purchases and sales contracts

recorded on the balance sheet at

December 31, 2021, as derivative instruments.

Using Monte Carlo simulation, a 95 percent

confidence level and a

one-day holding period, the VaR

for those instruments issued or held for

trading purposes or held for purposes

other than trading at December 31, 2021 and 2020, was

immaterial to our consolidated

cash flows and net income

attributable to ConocoPhillips.

Interest Rate Risk

The following table provides information

about our debt instruments that are

sensitive to changes in U.S. interest

rates.

The table presents principal cash flows

and related weighted-average

interest rates

by expected maturity

dates.

Weighted-average

variable rates are based

on effective rates

at the reporting date.

The carrying amount of

our floating-rate debt approximates

its fair value.

A hypothetical 10 percent change in

prevailing interest rates

would not have a material impact

on interest expense associated

with our floating-rate debt.

The fair value of the

fixed-rate debt is measured

using prices available from a pricing service that

is corroborated by

market data.

Changes to prevailing interest

rates would not impact our cash

flows associated with fixed rate

debt, unless we

elect to repurchase or retire such

debt prior to maturity.

ConocoPhillips

2021 10-K

72

Millions of Dollars Except as Indicated

Debt

Fixed

Average

Floating

Average

Rate

Interest

Rate

Interest

Expected Maturity Date

Maturity

Rate

Maturity

Rate

Year-End 2021

2022

$

346

2.53

%

$

500

1.03

%

2023

116

6.64

2024

459

3.51

2025

369

5.32

2026

1,355

5.06

Remaining years

14,338

5.80

283

0.11

Total

$

16,983

$

783

Fair value

$

21,668

$

783

Year-End 2020

2021

$

133

8.47

%

$

300

0.22

%

2022

346

2.53

500

1.12

2023

110

7.03

2024

459

3.51

2025

368

5.33

Remaining years

11,793

6.28

283

0.11

Total

$

13,209

$

1,083

Fair value

$

18,023

$

1,083

Foreign Currency Exchange

Risk

We have foreign

currency exchange rate

risk resulting from international

operations.

We do not comprehensively

hedge the exposure to currency

exchange rate changes

although we may choose to selectively

hedge certain

foreign currency exchange

rate exposures,

such as firm commitments for capital

projects or local currency tax

payments, dividends and cash returns

from net investments in foreign

affiliates to be remitted

within the coming

year,

and investments in equity securities.

At December 31, 2021 and 2020, we held foreign

currency exchange forwards

hedging cross-border commercial

activity and foreign currency exchange

swaps for purposes of mitigating

our cash-related exposures.

Although

these forwards and swaps

hedge exposures to fluctuations in exchange

rates, we elected not to

utilize hedge

accounting.

As a result, the change in the fair value of these foreign

currency exchange derivatives

is recorded

directly in earnings.

At December 31, 2021, we had outstanding

foreign currency exchange

forward contracts

to buy $1.9 billion AUD at

$0.715 AUD against the U.S. dollar.

At December 31, 2020, we had outstanding

foreign currency exchange

forward

contracts to sell $0.45 billion CAD at $0.748

CAD against the U.S. dollar.

Based on the assumed volatility in the fair

value calculation, the net fair value

of these foreign currency contracts

at December 31, 2021 and December 31,

2020, were a before-tax

gain of $21 million and before

-tax loss of $16 million, respectively.

Based on an adverse

hypothetical 10 percent change

in the December 2021 and December 2020 exchange

rate, this would result

in an

additional before-tax loss

of $134 million and $39 million, respectively.

The sensitivity analysis is based on

changing one assumption while holding all other assumptions constant,

which in practice may be unlikely

to occur,

as changes in some of the assumptions may be correlated.

73

ConocoPhillips

2021 10-K

The gross notional and fair value of these positions

at December 31, 2021 and 2020, were as follows

:

Foreign Currency Exchange

Derivatives

In Millions

Notional

Fair Value*

2021

2020

2021

2020

Sell Canadian dollar,

buy U.S. dollar

CAD

450

(16)

Buy Canadian dollar,

sell U.S. dollar

CAD

77

80

(1)

2

Buy Australian dollar,

sell U.S. dollar

AUD

1,850

21

Sell British pound, buy euro

GBP

239

8

(8)

Buy British pound, sell euro

GBP

394

3

7

*Denominated in USD.

For additional information about

our use of derivative instruments,

see Note 12

ConocoPhillips

2021 10-K

74

Item 8.

Financial Statements and Supplementary Data

ConocoPhillips

Index to Financial Statements

Page

Reports of Management

75

Reports of Independent Registered Public Accounting Firm

(PCAOB ID #

42

)

76

Consolidated Income Statement for the years ended December 31, 2021, 2020 and 2019

82

Consolidated Statement of Comprehensive Income for the years ended

December 31, 2021, 2020 and 2019

83

Consolidated Balance Sheet at December 31, 2021 and 2020

84

Consolidated Statement of Cash Flows for the years ended December 31, 2021, 2020 and 2019

85

Consolidated Statement of Changes in Equity for the years ended

December 31, 2021, 2020 and 2019

86

Notes to Consolidated Financial Statements

87

Supplementary Information

Oil and Gas Operations

149

75

ConocoPhillips

2021 10-K

Reports of Management

Management prepared, and is responsible

for,

the consolidated financial statements

and the other information

appearing in this annual report.

The consolidated financial statements

present fairly the company's

financial

position, results of operations and

cash flows in conformity with accounting

principles generally accepted in the

United States.

In preparing its consolidated financial

statements, the company

includes amounts that are based on

estimates and judgments management

believes are reasonable under the circumstances.

The company's financial

statements have

been audited by Ernst & Young

LLP,

an independent registered public accounting

firm appointed

by the Audit and Finance Committee of the Board of Directors

and ratified by stockholders.

Management has

made available to Ernst & Young

LLP all of the company's financial records

and related data, as well as the minutes

of stockholders' and directors'

meetings.

Assessment of Internal Control Over

Financial Reporting

Management is also responsible for establishing

and maintaining adequate internal

control over financial

reporting.

ConocoPhillips' internal control

system was designed to

provide reasonable assurance to

the company's

management and directors regarding

the preparation and fair presentatio

n

of published financial statements.

All internal control systems,

no matter how well designed, have

inherent limitations.

Therefore, even those

systems determined to

be effective can provide

only reasonable assurance with respect

to financial statement

preparation and presentation.

Management assessed the effectiveness

of the company's internal

control over financial reporting as

of

December 31, 2021.

In making this assessment, it used the criteria set forth

by the Committee of Sponsoring

Organizations of the Treadway

Commission in

Internal Control-Integrated

Framework (2013)

Based on our

assessment, we believe the company's

internal control over financial reporting

was effective as of

December 31, 2021.

Management's assessment

of, and conclusion on,

the effectiveness of internal control

over

financial reporting did not include the internal controls

of the assets acquired from Shell Enterprise LLC

in

December 2021.

The total assets acquired represented

approximately 10 percent

of the company's consolidated

total assets at December 31, 2021.

Ernst & Young

LLP has issued an audit report on the company's

internal control over financial reporting

as of

December 31, 2021, and their report is included herein.

/s/ Ryan M. Lance

/s/ William L. Bullock, Jr.

Ryan M. Lance

William L. Bullock, Jr.

Chairman and

Chief Executive Officer

Executive Vice President and

Chief Financial Officer

ConocoPhillips

2021 10-K

76

Report of Independent Registered

Public Accounting Firm

To the Stockholders

and the Board of Directors of ConocoPhillips

Opinion on the Financial Statements

We have audited the

accompanying consolidated

balance sheets of ConocoPhillips (the Company) as

of December

31, 2021 and 2020, the related consolidated

income statement, consolidated

statements of comprehensive

income, changes in equity and cash flows for

each of the three years in the period ended December 31, 2021, and

the related notes (collectively referred

to as the "consolidated

financial statements"). In our opinion,

the

consolidated financial statements

present fairly,

in all material respects, the financial position of the Company

as

of December 31, 2021 and 2020, and the results of its operations

and its cash flows for each of the three years

in

the period ended December 31, 2021, in conformity with

U.S. generally accepted accounting

principles.

We also have audited,

in accordance with the standards of the Public

Company Accounting Oversight

Board

(United States) (PCAOB), the Company's

internal control over financial reporting

as of December 31, 2021, based

on criteria established in Internal

Control-Integrated

Framework issued by the Committee

of Sponsoring

Organizations of the Treadway

Commission (2013 framework) and our report

dated February 17, 2022, expressed

an unqualified opinion thereon.

Basis for Opinion

These financial statements are

the responsibility of the Company's

management. Our responsibility is to express

an

opinion on the Company's financial statements

based on our audits. We are a public

accounting firm registered

with the PCAOB and are required to

be independent with respect to the Company

in accordance with the U.S.

federal securities laws and the applicable

rules and regulations of the Securities and Exchange

Commission and the

PCAOB.

We conducted our audits

in accordance with the standards of the PCAOB.

Those standards require that

we plan

and perform the audit to obtain reasonable

assurance about whether the financial statements

are free of material

misstatement, whether due to

error or fraud. Our audits included performing

procedures to assess the risks

of

material misstatement

of the financial statements, whether

due to error or fraud, and performing

procedures that

respond to those risks. Such procedures

included examining, on a test basis, evidence

regarding the amounts and

disclosures in the financial statements.

Our audits also included evaluating the accounting

principles used and

significant estimates made by management,

as well as evaluating the overall

presentation of the financial

statements. We

believe that our audits provide

a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated

below are matters

arising from the current period audit of the

consolidated financial statements

that were communicated

or required to be communicated

to the Audit and

Finance Committee and that: (1) relate

to accounts or disclosures that

are material to the consolidated financial

statements and (2) involved

our especially challenging, subjective or complex judgments.

The communication of

critical audit matters does not

alter in any way our opinion on the consolidated

financial statements, taken

as a

whole, and we are not, by communicating the

critical audit matters below,

providing separate opinions

on the

critical audit matters or on the accounts

or disclosures to which they relate.

77

ConocoPhillips

2021 10-K

Accounting for asset retirement

obligations for certain offshore properties

Description of

the Matter

At December 31, 2021, the asset retirement

obligation (ARO) balance totaled

$5.9 billion. As

further described in Note 8, the Company records

AROs in the period in which they are

incurred, typically when the asset is installed

at the production location. The estimation

of

obligations related to

certain offshore assets requires

significant judgment given the

magnitude and higher estimation uncertainty

related to plugging and abandonment of wells

and removal and disposal of offshore

oil and gas platforms, facilities

and pipelines costs

(collectively,

removal costs). Furthermore, given

certain of these assets are nearing the end

of their operations, the impact of changes in these AROs

may result in a material impact to

earnings given the relatively short remainin

g

useful lives of the assets.

Auditing the Company's AROs for

the obligations identified above is

complex and highly

judgmental due to the significant

estimation required by management

in determining the

obligations. In particular,

the estimates were sensitive to

significant subjective assumptions

such as removal cost estimates

and end of field life, which are affected

by expectations

about future market or economic conditions.

How We

Addressed the

Matter in Our

Audit

We obtained an understanding,

evaluated the design and tested

the operating effectiveness

of the Company's internal

controls over its ARO estimation

process, including management's

review of the significant assumptions that

have a material effect on the

determination of the

obligations. We also

tested management's controls

over the completeness and accuracy of

the financial data used in the valuation.

To test

the AROs for the obligations

identified above, our audit procedures included,

among

others, assessing the significant assumptions

and inputs used in the valuation, including

removal cost estimates

and end of field life assumptions. For example,

we evaluated

removal cost estimates

by comparing to settlements and

recent removal activities and costs.

We also compared end of field life

assumptions to production forecasts.

Depreciation, depletion and amortization of proved oil and

gas properties, plants and

equipment

Description of

the Matter

At December 31, 2021, the net book value

of the Company's proved

oil and gas properties,

plants and equipment (PP&E) was $52 billion, and

depreciation, depletion and amortization

(DD&A) expense was $7.0 billion for the year

then ended. As described in Note 1, under the

successful efforts method of accounting,

DD&A of PP&E on producing hydrocarbon

properties and steam-assisted

gravity drainage facilities

and certain pipeline and liquified

natural gas assets (those which are

expected to have a declining utilization

pattern) are

determined by the unit-of-production

method. The unit-of-production

method uses proved

oil and gas reserves, as estimated

by the Company's internal

reservoir engineers.

Proved oil and gas 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.

Significant judgment is required by

the Company's internal

reservoir engineers in evaluating

geological and engineering data when estimating

proved oil and gas reserves.

Estimating

proved oil and gas reserves also

requires the selection of inputs, including oil and gas

price

assumptions, future operating and

capital costs assumptions and tax

rates by jurisdiction,

among others. Because of the complexity involved

in estimating proved oil and gas

reserves,

management also used an independent petroleum

engineering consulting firm to perform a

review of the processes and controls

used by the Company's internal

reservoir engineers to

determine estimates of proved

oil and gas reserves.

ConocoPhillips

2021 10-K

78

Auditing the Company's DD&A calculation

is complex because of the use of the work of the

internal reservoir engineers and the

independent petroleum engineering consulting firm

and

the evaluation of management's

determination of the inputs described above used by

the

internal reservoir engineers in estimating

proved oil and gas reserves.

How We

Addressed the

Matter in Our

Audit

We obtained an understanding,

evaluated the design and tested

the operating effectiveness

of the Company's internal

controls over its processes

to calculate DD&A, including

management's controls

over the completeness and accuracy

of the financial data provided

to the internal reservoir engineers for

use in estimating proved oil and

gas reserves.

Our audit procedures included, among others,

evaluating the professional

qualifications and

objectivity of the Company's internal

reservoir engineers primarily responsible

for

overseeing the preparation

of the proved oil and gas reserve

estimates and the independent

petroleum engineering consulting firm used to

review the Company's

processes and

controls. In addition, in assessing whether we can

use the work of the internal reservoir

engineers, we evaluated the completeness

and accuracy of the financial data and inputs

described above used by the internal reservoir

engineers in estimating proved

oil and gas

reserves by agreeing them to source

documentation and we identified and

evaluated

corroborative and contrary

evidence. We also tested the accuracy

of the DD&A calculation,

including comparing the proved oil and gas

reserve amounts used in the calculation to

the

Company's reserve report.

Valuation and recognition of

proved and unproved oil & gas properties acquired in

business combinations

Description of

the Matter

During 2021, the Company closed its acquisition of Concho Resources

Inc. and its acquisition

of Permian assets from Shell Enterprises

LLC resulting in the recognition of proved

and

unproved oil and gas properties

within net properties, plants and equipment of $18.9 billion

and $8.6 billion, respectively.

As described in Note 3, the transactions were

accounted for as

business combinations under FASB

ASC 805 using the acquisition method, which requires

assets acquired and liabilities assumed to be measured

at their acquisition date fair values.

Oil and gas properties were valued

using a discounted cash flow approach

based on market

participant assumptions and third party valuation

experts were engaged by the Company

to

prepare fair value estimates.

Significant inputs to the valuation

of proved and unproved oil

and gas properties include estimates

of future commodity price assumptions and

production

profiles of reserve estimates, the

pace of drilling plans, future operating costs

and discount

rates using a market

-based weighted average cost

of capital.

Auditing the Company's accounting for

its valuation of proved and unproved

oil and gas

properties is complex and considerably

judgmental due to the significant estimation

required by management of reserves

and resources associated with the acquired

assets and

the sensitivity of significant assumptions used in determining

the fair value.

In evaluating

the reasonableness of management's

estimates and assumptions used, the audit

testing

procedures performed required

a high degree of auditor judgment and additional effort,

including involving internal specialists.

How We

Addressed the

Matter in Our

Audit

We obtained an understanding,

evaluated the design and tested

the operating effectiveness

of the Company's internal

controls over its process

to estimate the fair value of the acquired

proved and unproved

oil and gas properties, including management's

review of the

significant assumptions used as inputs to

the fair value calculations and final recording

of

the analysis.

79

ConocoPhillips

2021 10-K

To test

the estimated fair value of the acquired

proved and unproved

oil and gas properties,

our audit procedures included, among others,

evaluating the significant assumptions

used

and testing the completeness and accuracy

of the underlying data supporting the significant

assumptions. For example, we compared

certain significant assumptions

to current industry,

third-party data and historical

results for reasonableness. We

also performed sensitivity

analyses of significant assumptions, to

evaluate the extent of their impact to the

fair value

calculation. In addition, we involved

our valuation specialists to assist

with certain significant

assumptions included in the fair value estimate.

Furthermore, we evaluated

the professional

qualifications and objectivity of the third party

valuation specialist engaged by the Company

to prepare the fair value of the acquired

proved and unproved oil and

gas properties.

/s/ Ernst & Young

LLP

We have served as ConocoPhillips'

auditor since 1949.

Houston, Texas

February 17, 2022

ConocoPhillips

2021 10-K

80

Report of Independent Registered

Public Accounting Firm

To the Stockholders

and the Board of Directors of ConocoPhillips

Opinion on Internal Control over Financial Reporting

We have audited ConocoPhillips'

internal control over financial reporting

as of December 31, 2021, based on

criteria established in Internal Control

-Integrated Framework

issued by the Committee of Sponsoring

Organizations of the Treadway

Commission (2013 framework) (the COSO criteria).

In our opinion, ConocoPhillips

(the Company) maintained, in all material

respects, effective internal

control over financial reporting

as of

December 31, 2021, based on the COSO criteria. As indicated

under the heading "Assessment

of Internal Control

Over Financial Reporting" in the accompanying Reports of Management,

management's assessment

of and

conclusion on the effectiveness

of internal control over financial reporting

did not include the internal controls

of

the assets acquired from Shell Enterprise

LLC, which is included in the 2021 consolidated financial

statements of

ConocoPhillips and constituted approximately

10 percent of consolidated total

assets as of December 31, 2021.

Our audit of internal control over

financial reporting of ConocoPhillips also did not

include an evaluation of the

internal control over financial

reporting of the assets acquired from Shell Enterprise

LLC.

We also have audited,

in accordance with the standards of the Public

Company Accounting Oversight

Board

(United States) (PCAOB), the consolidated

balance sheets of the Company as of December 31, 2021 and 2020, the

related consolidated income statement,

consolidated statements

of comprehensive income, changes in equity

and

cash flows for each of the three years

in the period ended December 31, 2021, and the related notes

and our

report dated February 17, 2022, expressed

an unqualified opinion thereon.

Basis for Opinion

The Company's management

is responsible for maintaining effective

internal control over

financial reporting and

for its assessment of the effectiveness

of internal control over financial reporting

included under the heading

"Assessment

of Internal Control Over Financial Reporting" in the

accompanying "Reports of Management."

Our

responsibility is to express an opinion

on the Company's internal control

over financial reporting based on our

audit. We are a public accounting

firm registered with the PCAOB and are

required to be independent with respect

to the Company in accordance with the U.S.

federal securities laws and

the applicable rules and regulations of the

Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance

with the standards of the PCAOB. Those

standards require that

we plan and

perform the audit to obtain reasonable

assurance about whether effective

internal control over financial

reporting

was maintained in all material respects.

Our audit included obtaining an understanding

of internal control over financial

reporting, assessing the risk that a

material weakness exists, testing

and evaluating the design and operating

effectiveness of internal control

based

on the assessed risk, and performing such other procedures

as we considered necessary in the circumstances.

We

believe that our audit provides a reasonable

basis for our opinion.

81

ConocoPhillips

2021 10-K

Definition and Limitations of Internal

Control Over Financial Reporting

A company's internal

control over financial reporting is a process

designed to provide reasonable assurance

regarding the reliability of financial reporting

and the preparation of financial statements

for external purposes in

accordance with generally accepted

accounting principles. A company's

internal control over financial reporting

includes those policies and procedures that

(1) pertain to the maintenance of records

that, in reasonable detail,

accurately and fairly reflect

the transactions and dispositions of the assets

of the company; (2) provide reasonable

assurance that transactions

are recorded as necessary to permit preparation

of financial statements in accordance

with generally accepted accounting

principles, and that receipts and expenditures

of the company are being made

only in accordance with authorizations

of management and directors of the company;

and (3) provide reasonable

assurance regarding prevention

or timely detection of unauthorized acquisition, use,

or disposition of the

company's assets that

could have a material effect

on the financial statements.

Because of its inherent limitations,

internal control over financial reporting

may not prevent or detect

misstatements. Also,

projections of any evaluation

of effectiveness to future periods

are subject to the risk that

controls may become inadequate

because of changes in conditions, or that the

degree of compliance with the

policies or procedures may deteriorate.

/s/

Ernst & Young LLP

Houston, Texas

February 17, 2022

Financial Statements

ConocoPhillips

2021 10-K

82

Consolidated Income Statement

ConocoPhillips

Years Ended

December 31

Millions of Dollars

2021

2020

2019

Revenues and Other Income

Sales and other operating revenues

$

45,828

18,784

32,567

Equity in earnings of affiliates

832

432

779

Gain on dispositions

486

549

1,966

Other income (loss)

1,203

(509)

1,358

Total

Revenues and Other Income

48,349

19,256

36,670

Costs and Expenses

Purchased commodities

18,158

8,078

11,842

Production and operating expenses

5,694

4,344

5,322

Selling, general and administrative

expenses

719

430

556

Exploration expenses

344

1,457

743

Depreciation, depletion and amortization

7,208

5,521

6,090

Impairments

674

813

405

Taxes

other than income taxes

1,634

754

953

Accretion on discounted liabilities

242

252

326

Interest and debt expense

884

806

778

Foreign currency transaction

(gains) losses

(22)

(72)

66

Other expenses

102

13

65

Total

Costs and Expenses

35,637

22,396

27,146

Income (loss) before income taxes

12,712

(3,140)

9,524

Income tax provision (benefit)

4,633

(485)

2,267

Net income (loss)

8,079

(2,655)

7,257

Less: net income attributable to noncontrolling

interests

(46)

(68)

Net Income (Loss) Attributable

to ConocoPhillips

$

8,079

(2,701)

7,189

Net Income (Loss) Attributable

to ConocoPhillips Per Share

of Common Stock

(dollars)

Basic

$

6.09

(2.51)

6.43

Diluted

6.07

(2.51)

6.40

Average Common Shares

Outstanding

(in thousands)

Basic

1,324,194

1,078,030

1,117,260

Diluted

1,328,151

1,078,030

1,123,536

See Notes to Consolidated Financial Statements.

Financial Statements

83

ConocoPhillips

2021 10-K

Consolidated Statement

of Comprehensive Income

ConocoPhillips

Years Ended

December 31

Millions of Dollars

2021

2020

2019

Net Income (Loss)

$

8,079

(2,655)

7,257

Other comprehensive income (loss)

Defined benefit plans

Prior service credit arising during the period

29

Reclassification adjustment for

amortization of prior

service credit included in net income (loss)

(38)

(32)

(35)

Net change

(38)

(3)

(35)

Net actuarial gain (loss) arising during the period

357

(210)

(55)

Reclassification adjustment for

amortization of net

actuarial losses included in net income (loss)

178

117

146

Net change

535

(93)

91

Nonsponsored plans*

5

1

(3)

Income taxes on defined benefit

plans

(108)

20

(2)

Defined benefit plans, net of tax

394

(75)

51

Unrealized holding gain (loss) on

securities

(2)

2

Reclassification adjustment for

loss included in net income

(1)

Income taxes on unrealized

holding loss on securities

1

Unrealized holding gain (loss) on securities,

net of tax

(2)

2

Foreign currency translation

adjustments

(124)

209

699

Income taxes on foreign

currency translation adjustments

3

(4)

Foreign currency translation

adjustments, net of tax

(124)

212

695

Other Comprehensive Income, Net of Tax

268

139

746

Comprehensive Income (Loss)

8,347

(2,516)

8,003

Less: comprehensive income attributable

to noncontrolling interests

(46)

(68)

Comprehensive Income (Loss) Attributable

to ConocoPhillips

$

8,347

(2,562)

7,935

*Plans for which ConocoPhillips is not the primary obligor-primarily those administered by equity

affiliates.

See Notes to Consolidated Financial Statements.

Financial Statements

ConocoPhillips

2021 10-K

84

Consolidated Balance Sheet

ConocoPhillips

At December 31

Millions of Dollars

2021

2020

Assets

Cash and cash equivalents

$

5,028

2,991

Short-term investments

446

3,609

Accounts and notes receivable (net of allowance

of $

2

and $

4

, respectively)

6,543

2,634

Accounts and notes receivable-related

parties

127

120

Investment in Cenovus Energy

1,117

1,256

Inventories

1,208

1,002

Prepaid expenses and other current

assets

1,581

454

Total

Current Assets

16,050

12,066

Investments and long-term receivables

7,113

8,017

Loans and advances-related parties

114

Net properties, plants and equipment

(net of accumulated DD&A of $

64,735

and $

62,213

, respectively)

64,911

39,893

Other assets

2,587

2,528

Total

Assets

$

90,661

62,618

Liabilities

Accounts payable

$

5,002

2,669

Accounts payable-related

parties

23

29

Short-term debt

1,200

619

Accrued income and other taxes

2,862

320

Employee benefit obligations

755

608

Other accruals

2,179

1,121

Total

Current Liabilities

12,021

5,366

Long-term debt

18,734

14,750

Asset retirement obligations

and accrued environmental costs

5,754

5,430

Deferred income taxes

6,179

3,747

Employee benefit obligations

1,153

1,697

Other liabilities and deferred credits

1,414

1,779

Total

Liabilities

45,255

32,769

Equity

Common stock (

2,500,000,000

shares authorized at $

0.01

par value)

Issued (2021-

2,091,562,747

shares; 2020-

1,798,844,267

shares)

Par value

21

18

Capital in excess of par

60,581

47,133

Treasury stock

(at cost: 2021-

789,319,875

shares; 2020-

730,802,089

shares)

(50,920)

(47,297)

Accumulated other comprehensive

loss

(4,950)

(5,218)

Retained earnings

40,674

35,213

Total

Equity

45,406

29,849

Total

Liabilities and Equity

$

90,661

62,618

See Notes to Consolidated Financial Statements.

Financial Statements

85

ConocoPhillips

2021 10-K

Consolidated Statement

of Cash Flows

ConocoPhillips

Years Ended

December 31

Millions of Dollars

2021

2020

2019

Cash Flows From Operating Activities

Net income (loss)

$

8,079

(2,655)

7,257

Adjustments to reconcile net income

(loss) to net cash provided by

operating activities

Depreciation, depletion and amortization

7,208

5,521

6,090

Impairments

674

813

405

Dry hole costs and leasehold impairments

44

1,083

421

Accretion on discounted liabilities

242

252

326

Deferred taxes

1,346

(834)

(444)

Undistributed equity earnings

446

645

594

Gain on dispositions

(486)

(549)

(1,966)

(Gain) loss on CVE common shares

(1,040)

855

(649)

Other

(788)

43

(351)

Working capital adjustments

Decrease (increase) in accounts and notes

receivable

(2,500)

521

505

Increase in inventories

(160)

(25)

(67)

Decrease (increase) in prepaid expenses

and other current

assets

(649)

76

37

Increase (decrease) in accounts payable

1,399

(249)

(378)

Increase (decrease) in taxes

and other accruals

3,181

(695)

(676)

Net Cash Provided by Operating

Activities

16,996

4,802

11,104

Cash Flows From Investing Activities

Capital expenditures and investments

(5,324)

(4,715)

(6,636)

Working capital changes

associated with investing activities

134

(155)

(103)

Acquisition of businesses, net of cash acquired

(8,290)

Proceeds from asset dispositions

1,653

1,317

3,012

Net sales (purchases) of investments

3,091

(658)

(2,910)

Collection of advances/loans-related parties

105

116

127

Other

87

(26)

(108)

Net Cash Used in Investing Activities

(8,544)

(4,121)

(6,618)

Cash Flows From Financing Activities

Issuance of debt

300

Repayment of debt

(505)

(254)

(80)

Issuance of company common stock

145

(5)

(30)

Repurchase of company common

stock

(3,623)

(892)

(3,500)

Dividends paid

(2,359)

(1,831)

(1,500)

Other

7

(26)

(119)

Net Cash Used in Financing Activities

(6,335)

(2,708)

(5,229)

Effect of Exchange

Rate Changes on Cash, Cash Equivalents

and

Restricted Cash

(34)

(20)

(46)

Net Change in Cash, Cash Equivalents and

Restricted Cash

2,083

(2,047)

(789)

Cash, cash equivalents and restricted

cash at beginning of period

3,315

5,362

6,151

Cash, Cash Equivalents and Restricted

Cash at End of Period

$

5,398

3,315

5,362

Restricted cash of $

152

million and $

218

million is included in the "Prepaid expenses and other current assets" and "Other assets"

lines,

respectively, of our Consolidated Balance Sheet as of December 31, 2021.

Restricted cash of $

94

million and $

230

million is included in the "Prepaid expenses and other current assets" and "Other assets" lines,

respectively, of our Consolidated Balance Sheet as of December 31, 2020.

See Notes to Consolidated Financial Statements.

Financial Statements

ConocoPhillips

2021 10-K

86

Consolidated Statement

of Changes in Equity

ConocoPhillips

Millions of Dollars

Attributable to ConocoPhillips

Common Stock

Par

Value

Capital in

Excess of

Par

Treasury

Stock

Accum. Other

Comprehensive

Income (Loss)

Retained

Earnings

Non-

Controlling

Interests

Total

Balances at December 31, 2018

$

18

46,879

(42,905)

(6,063)

34,010

125

32,064

Net income

7,189

68

7,257

Other comprehensive loss

746

746

Dividends declared-ordinary ($

1.34

per share of common stock)

(1,500)

(1,500)

Repurchase of company common stock

(3,500)

(3,500)

Distributions to noncontrolling interests and other

(128)

(128)

Distributed under benefit plans

104

104

Changes in Accounting Principles*

(40)

40

Other

3

4

7

Balances at December 31, 2019

$

18

46,983

(46,405)

(5,357)

39,742

69

35,050

Net income (loss)

(2,701)

46

(2,655)

Other comprehensive income

139

139

Dividends declared-ordinary ($

1.69

per share of common stock)

(1,831)

(1,831)

Repurchase of company common stock

(892)

(892)

Distributions to noncontrolling interests and other

(32)

(32)

Disposition

(84)

(84)

Distributed under benefit plans

150

150

Other

3

1

4

Balances at December 31, 2020

$

18

47,133

(47,297)

(5,218)

35,213

29,849

Net income

8,079

8,079

Other comprehensive income

268

268

Dividends declared

Ordinary ($

1.75

per share of common stock)

(2,359)

(2,359)

Variable return of cash ($

0.20

per share of common stock)

(260)

(260)

Acquisition of Concho

3

13,122

13,125

Repurchase of company common stock

(3,623)

(3,623)

Distributed under benefit plans

326

326

Other

1

1

Balances at December 31, 2021

$

21

60,581

(50,920)

(4,950)

40,674

45,406

*Cumulative effect of the adoption of ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income."

See Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements

87

ConocoPhillips

2021 10-K

Notes to Consolidated

Financial Statements

Note 1-Accounting Policies

●

Consolidation Principles and Investments

-Our consolidated financial statements

include the accounts of

majority-owned, controlled subsidiaries

and, if applicable, variable interest

entities where we are the

primary beneficiary.

The equity method is used to account for

investments in affiliates

in which we have

the ability to exert significant

influence over the affiliates' operating

and financial policies.

When we do

not have the ability to exert

significant influence, the investment

is measured at fair value except

when

the investment does not have

a readily determinable fair value.

For those exceptions, it will be measured

at cost minus impairment, plus or minus

observable price changes in orderly transactions for

an identical

or similar investment of the same issuer.

Undivided interests in oil and gas

joint ventures, pipelines,

natural gas plants and terminals

are consolidated on a proportionate

basis.

Other securities and

investments are generally

carried at cost.

We manage our operations

through

six

operating segments,

defined by geographic region:

Alaska; Lower 48; Canada; Europe, Middle

East and North Africa; Asia

Pacific; and Other International.

See Note 23

●

Foreign Currency Translation

-Adjustments resulting from the

process of translating foreign

functional

currency financial statements

into U.S. dollars are included

in accumulated other comprehensive

loss in

common stockholders' equity.

Foreign currency transaction

gains and losses are included in current

earnings.

Some of our foreign operations

use their local currency as the functional currency.

●

Use of Estimates

-The preparation of financial statements

in conformity with U.S. GAAP requires

management to make estimates

and assumptions that affect the

reported amounts of assets, liabilities,

revenues and expenses and the disclosures

of contingent assets and liabilities.

Actual results could differ

from these estimates.

●

Revenue Recognition

-Revenues associated with

the sales of crude oil, bitumen, natural gas,

LNG, NGLs

and other items are recognized

at the point in time when the customer obtains

control of the asset.

In

evaluating when a customer has control

of the asset, we primarily consider whether the transfer

of legal

title and physical delivery has occurred,

whether the customer has significant risks

and rewards of

ownership and whether the customer has

accepted delivery and a right to payment

exists.

These

products are typically sold at prevailing

market prices.

We allocate variable

market-based consideration

to deliveries (performance obligations)

in the current period as that consideration

relates specifically to

our efforts to transfer

control of current period deliveries

to the customer and represents

the amount we

expect to be entitled to in exchange

for the related products.

Payment is typically due within 30 days or

less.

Revenues associated with transactions

commonly called buy/sell contracts,

in which the purchase and

sale of inventory with the same counterparty

are entered into "in contemplation"

of one another, are

combined and reported net (i.e., on the same income

statement line).

●

Shipping and Handling Costs

-We typically incur shipping and handling

costs prior to control transferring

to the customer and account for

these activities as fulfillment costs.

Accordingly,

we include shipping and

handling costs in production and operating

expenses for production activities.

Transportation

costs

related to marketing activities

are recorded in purchased commodities.

Freight costs billed to customers

are treated as a component of the transaction

price and recorded as a component of revenue

when the

customer obtains control.

●

Cash Equivalents

-Cash equivalents are highly liquid, short-term

investments that are

readily convertible

to known amounts of cash and have

original maturities of 90 days or less from their date

of purchase.

They are carried at cost plus accrued interest,

which approximates fair value.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

88

●

Short-Term

Investments

-Short-term investments

include investments in bank time deposits

and

marketable securities (commercial

paper and government obligations)

which are carried at cost plus

accrued interest and have

original maturities of greater than 90 days

but within one year or when the

remaining maturities are within one year.

We also invest in financial instruments

classified as available

for sale debt securities which are carried at

fair value. Those instruments

are included in short-term

investments when they have

remaining maturities within one year as of the balance

sheet date.

●

Long-Term Investments

in Debt Securities

-Long-term investments

in debt securities includes financial

instruments classified as available

for sale debt securities with remaining maturities

greater than one year

as of the balance sheet date.

They are carried at fair value

and presented within the "Investments

and

long-term receivables" line of our consolidated

balance sheet.

●

Inventories

-We have several

valuation methods for our various

types of inventories and consistently

use

the following methods for each type

of inventory.

The majority of our commodity-related inventories

are

recorded at cost using the

LIFO basis.

We measure these inventories

at the lower-of-cost-or-market

in

the aggregate.

Any necessary lower-of-cost-or-market

write-downs at year end are recorded

as

permanent adjustments to the LIFO cost

basis.

LIFO is used to better match current

inventory costs with

current revenues.

Costs include both direct and indirect expenditures

incurred in bringing an item or

product to its existing condition

and location, but not unusual/nonrecurring costs

or research and

development costs.

Materials, supplies and other miscellaneous inventories,

such as tubular goods and

well equipment, are valued using various

methods, including the weighted-average

-cost method and the

FIFO method, consistent with industry

practice.

●

Fair Value Measurements

-Assets and liabilities measured at fair value

and required to be categorized

within the fair value hierarchy

are categorized into

one of three different

levels depending on the

observability of the inputs employed in the measurement.

Level 1 inputs are quoted prices in active

markets for identical assets

or liabilities.

Level 2 inputs are observable inputs other than

quoted prices

included within Level 1 for the asset or liability,

either directly or indirectly through market

-corroborated

inputs.

Level 3 inputs are unobservable inputs for

the asset or liability reflecting significant modifications

to observable related market

data or our assumptions about pricing by market

participants.

●

Derivative Instruments

-Derivative instruments are

recorded on the balance sheet at fair

value.

If the

right of offset exists and certain

other criteria are met, derivative assets

and liabilities with the same

counterparty are netted

on the balance sheet and the collateral payable

or receivable is netted against

derivative assets and derivative

liabilities, respectively.

Recognition and classification of the gain

or loss that results from recording

and adjusting a derivative to

fair value depends on the purpose for

issuing or holding the derivative.

Gains and losses from derivatives

not accounted for as hedges

are recognized immediately in

earnings.

We do not apply hedge accounting

to our derivative instruments.

●

Oil and Gas Exploration and Development

-Oil and gas exploration and

development costs are

accounted for using the successful

efforts method of accounting.

Property Acquisition Costs

-Oil and gas leasehold acquisition costs

are capitalized and included in

the balance sheet caption PP&E.

Leasehold impairment is recognized based on

exploratory

experience and management's

judgment.

Upon achievement of all conditions necessary for

reserves

to be classified as proved, the associated

leasehold costs are reclassified to proved

properties.

Exploratory Costs

-Geological and geophysical

costs and the costs of carrying and retaining

undeveloped properties are expensed

as incurred.

Exploratory well costs are

capitalized, or

"suspended,"

on the balance sheet pending further evaluation of whether economically

recoverable

reserves have been found.

If economically recoverable reserves

are not found, exploratory

well costs

are expensed as dry holes.

If exploratory wells encounter

potentially economic quantities

of oil and

Notes to Consolidated Financial Statements

89

ConocoPhillips

2021 10-K

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.

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 all required approvals

and permits have been

obtained, the projects are moved

into the development phase, and the

oil and gas resources are

designated as proved reserves.

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 dry holes

when it judges the potential field does not warrant

further investment in the near term.

See Note 6

Development Costs

-Costs incurred to drill and equip development

wells, including unsuccessful

development wells, are capital

ized.

Depletion and Amortization

-Leasehold costs of producing properties

are depleted using the unit-of-

production method based on estimated

proved oil and gas reserves.

Amortization of development

costs is based on the unit-of-production

method using estimated proved

developed oil and gas

reserves.

●

Capitalized Interest

-Interest from external

borrowings is capitalized on

major projects with an expected

construction period of one year or longer.

Capitalized interest

is added to the cost of the underlying asset

and is amortized over the useful lives of the assets

in the same manner as the underlying assets.

●

Depreciation and Amortization

-Depreciation and amortization of PP&E

on producing hydrocarbon

properties and SAGD facilities and

certain pipeline and LNG assets (those which are expected

to have a

declining utilization pattern),

are determined by the unit-of-production

method.

Depreciation and

amortization of all other PP&E are determined by

either the individual-unit-straight-line

method or the

group-straight-line

method (for those individual units that are

highly integrated with other units).

●

Impairment of Properties, Plants and Equipment

-Long-lived assets used in operations are assessed

for

impairment whenever changes in facts

and circumstances indicate a possible

significant deterioration in

the future cash flows expected

to be generated by an asset group.

If 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 plans.

If the sum of the undiscounted cash

flows before income-taxes

is less than the carrying value of the asset group,

the carrying value is written

down to estimated fair value

and reported as an impairment in the period 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 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

are based

on estimated future production

volumes, commodity prices,

operating costs and capital

decisions,

considering all available evidence at the date

of review.

The impairment review includes cash

flows from

proved developed and undeveloped

reserves, including any development

expenditures necessary to

achieve that production.

Additionally, when probable

and possible reserves exist, an appropriate

risk-

adjusted amount of these reserves may

be included in the impairment calculation.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

90

Long-lived assets committed by

management for disposal within one year are

accounted for at the lower

of amortized cost or fair value,

less cost to sell, with fair value determined

using a binding negotiated

price, if available, or present value

of expected future cash flows

as previously described.

●

Maintenance and Repairs

-Costs of maintenance and repairs,

which are not significant improvements,

are expensed when incurred.

●

Property Dispositions

-When complete units of depreciable

property are sold, the asset cost

and related

accumulated depreciation are

eliminated, with any gain or loss

reflected in the "Gain on dispositions" line

of our consolidated income statement.

When partial units of depreciable property are

disposed of or

retired which do not significantly

alter the DD&A rate, the difference

between asset cost and salvage

value is charged or credited to

accumulated depreciation.

●

Asset Retirement Obligations

and Environmental Costs

-The

fair value of legal obligations

to retire and

remove long-lived assets are recorded

in the period in which the obligation is incurred

(typically when the

asset is installed at the production

location).

Fair value is estimated using

a present value approach,

incorporating assumptions about estimated

amounts and timing of settlements and impacts

of the use of

technologies.

See Note 8

Environmental expenditures

are expensed or capitalized,

depending upon their future economic benefit.

Expenditures relating to an existing

condition caused by past operations,

and those having no future

economic benefit, are expensed.

Liabilities for environmental

expenditures are recorded

on an

undiscounted basis (unless acquired through

a business combination, which we record

on a discounted

basis) when environmental assessments

or cleanups are probable and the costs

can be reasonably

estimated.

Recoveries of environmental

remediation costs from other parties

are recorded as assets

when their receipt is probable and estimable.

●

Impairment of Investments

in Nonconsolidated Entities

-Investments in nonconsolidated

entities are

assessed for impairment whenever changes

in the facts and circumstances

indicate a loss in value has

occurred.

When such a condition is judgmentally determined

to be other than temporary,

the carrying

value of the investment is written

down to fair value.

The fair value of the impaired investment

is based

on quoted market prices, if available,

or upon 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.

●

Guarantees

-The fair value of a guarantee

is determined and recorded as a

liability at the time the

guarantee is given.

The initial liability is subsequently reduced as we are

released from exposure

under

the guarantee.

We amortize the guarantee

liability over the relevant time period, if one

exists, based on

the facts and circumstances surrounding

each type of guarantee.

In cases where the guarantee term

is

indefinite, we reverse the liability

when we have information

indicating the liability is essentially relieved

or amortize it over an appropriate

time period as the fair value of our guarantee

exposure declines over

time.

We amortize the guarantee

liability to the related income statement

line item based on the nature

of the guarantee.

When it becomes probable that we will have

to perform on a guarantee, we accrue

a

separate liability if it is reasonably estimable,

based on the facts and circumstances

at that time.

We

reverse the fair value liability

only when there is no further exposure under the

guarantee.

●

Share-Based Compensation

-We recognize share

-based compensation expense over

the shorter of the

service period (i.e., the stated period of time required

to earn the award) or the period beginning at

the

start of the service period and ending when an employee first

becomes eligible for retirement.

We have

elected to recognize expense

on a straight-line basis over the service period for

the entire award, whether

the award was granted

with ratable or cliff vesting.

Notes to Consolidated Financial Statements

91

ConocoPhillips

2021 10-K

●

Income Taxes

-Deferred income taxes

are computed using the liability method

and are provided on all

temporary differences

between the financial reporting basis and the tax

basis of our assets and liabilities,

except for deferred

taxes on income and temporary

differences related

to the cumulative translation

adjustment considered to be permanently

reinvested in certain

foreign subsidiaries and foreign

corporate

joint ventures.

Allowable tax credits are applied currently

as reductions of the provision for

income taxes.

Interest related to

unrecognized tax benefits

is reflected in interest

and debt expense, and penalties

related to unrecognized

tax benefits are reflected

in production and operating

expenses.

●

Taxes

Collected from Customers

and Remitted to Governmental

Authorities

-Sales and value-added

taxes are recorded

net.

●

Net Income (Loss) Per Share of Common

Stock

-Basic net income (loss) per share of common stock

is

calculated based upon the daily weighted-average

number of common shares outstanding

during the

year.

Also, this

calculation includes fully vested stock

and unit awards that have not

yet been issued as

common stock, along with an adjustment

to net income (loss) for dividend equivalents

paid on unvested

unit awards that are considered

participating securities.

Diluted net income per share of common stock

includes unvested stock,

unit or option awards granted

under our compensation plans and vested but

unexercised stock

options, but only to the extent these instruments

dilute net income per share, primarily

under the treasury-stock method.

Diluted net loss per share, which is calculated

the same as basic net

loss per share, does not assume conversion

or exercise of securities that

would have an antidilutive effect.

Treasury stock

is excluded from the daily weighted

-average number of common

shares outstanding in

both calculations.

The earnings per share impact of the participating securities is immaterial.

Note 2-Inventories

Inventories at December 31 were:

Millions of Dollars

2021

2020

Crude oil and natural gas

$

647

461

Materials and supplies

561

541

Total

inventories

$

1,208

1,002

Inventories valued on

the LIFO basis

$

395

282

The estimated excess

of current replacement cost over

LIFO cost of inventories

was approximately $

251

million

and $

87

million at December 31, 2021 and 2020, respectively.

Note 3-Asset Acquisitions and Dispositions

All gains or losses on asset dispositions are reported

before-tax and are included

net in the "Gain on dispositions"

line on our consolidated income stat

ement.

All cash proceeds and payments are

included in the "Cash Flows From

Investing Activities" section of our consolidated

statement of cash flows.

During the year,

we completed the acquisitions of Concho Resources

Inc. (Concho) and of Shell Enterprises LLC's

(Shell) Permian assets.

The acquisitions were accounted for

as business combinations under FASB

Topic ASC 805

using the acquisition method, which requires assets

acquired and liabilities assumed to be measured at their

acquisition date fair values.

Fair value measurements were

made for acquired assets and liabilities, and

adjustments to those measurements

may be made in subsequent periods, up to

one year from the acquisition date

as we identify new information

about facts and circumstances that

existed as of the acquisition date to

consider.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

92

2021

Acquisition of Concho Resources Inc.

In January 2021, we completed our acquisition of Concho,

an independent oil and gas exploration

and production

company with operations across

New Mexico and West Texas

focused in the Permian Basin.

Total

consideration

for the all-stock transaction

was valued at $

13.1

billion, in which 1.46 shares of ConocoPhillips common stock

were

exchanged for each outstanding

share of Concho common stock.

Total Consideration

Number of shares of Concho common stock issued

and outstanding (in thousands)*

194,243

Number of shares of Concho stock awards

outstanding (in thousands)*

1,599

Number of shares exchanged

195,842

Exchange ratio

1.46

Additional shares of ConocoPhillips common stock

issued as consideration (in thousands)

285,929

Average price per share of ConocoPhillips

common stock**

$

45.9025

Total Consideration

(Millions)

$

13,125

*Outstanding as of January 15, 2021.

**Based on the ConocoPhillips average stock price on January 15, 2021.

Oil and gas properties were valued

using a discounted cash flow approach

incorporating market

participant and

internally generated price assumptions;

production profiles; and operating

and development cost assumptions.

Debt assumed in the acquisition was valued based on

observable market prices.

The fair values determined for

accounts receivable, accounts

payable, and most other current

assets and current liabilities were equivalent

to the

carrying value due to their short-term

nature.

The total consideration of $

13.1

billion was allocated to the

identifiable assets and liabilities based on their fair

values as of January 15, 2021.

Assets Acquired

Millions of Dollars

Cash and cash equivalents

$

382

Accounts receivable, net

745

Inventories

45

Prepaid expenses and other current

assets

37

Investments and long-term receivables

333

Net properties, plants and equipment

18,923

Other assets

62

Total assets

acquired

$

20,527

Liabilities Assumed

Accounts payable

$

638

Accrued income and other taxes

56

Employee benefit obligations

4

Other accruals

510

Long-term debt

4,696

Asset retirement obligations

and accrued environmental costs

310

Deferred income taxes

1,071

Other liabilities and deferred credits

117

Total liabilities

assumed

$

7,402

Net assets acquired

$

13,125

Notes to Consolidated Financial Statements

93

ConocoPhillips

2021 10-K

With the completion of the Concho transaction,

we acquired proved and unproved

properties of approximately

$

11.8

billion and $

6.9

billion, respectively.

We recognized approximately

$

157

million of transaction-related costs,

all of which were expensed in the first

quarter of 2021.

These non-recurring costs related

primarily to fees paid to advisors

and the settlement of share-

based awards for certain Concho

employees based on the terms of the Merger Agreement.

In the first quarter of 2021, we commenced

a company-wide restructuring program,

the scope of which included

combining the operations of the two companies

as well as other global restructuring activities.

We recognized

non-recurring restructuring costs

mainly for employee severance and

related incremental pension

benefit costs.

The impact from these transaction and restructuring

costs to the lines of our consolidated income statement

for

the year ended December 31, 2021, are below:

Millions of Dollars

Transaction

Cost

Restructuring Cost

Total

Cost

Production and operating expenses

$

128

128

Selling, general and administration

expenses

135

67

202

Exploration expenses

18

8

26

Taxes

other than income taxes

4

2

6

Other expenses

29

29

$

157

234

391

On February 8, 2021, we completed a debt

exchange offer

related to the debt assumed from Concho.

As a result

of the debt exchange, we recognized

an additional income tax related

restructuring charge of $

75

million.

Note 17.

From the acquisition date through

December 31, 2021, "Total Revenues

and Other Income" and "Net Income

(Loss) Attributable to ConocoPhillips"

associated with the acquired Concho business

were approximately $

6,571

million and $

2,330

million, respectively.

The results associated with the Concho business

for the same period

include a before- and after-tax

loss of $

305

million and $

233

million, respectively,

on the acquired derivative

contracts.

The before-tax loss is recorded

within "Total Revenues

and Other Income" on our consolidated

income

statement.

See Note 12.

Acquisition of Shell Permian Assets

In December 2021, we completed our acquisition

of Shell assets in the Permian based Delaware Basin.

The

accounting close date used for reporting

purposes was December 31, 2021.

Assets acquired include approximately

225,000

net acres and producing properties

located entirely in Texas.

Total

consideration for the transaction

was

$

8.7

billion.

Oil and gas properties were valued

using a discounted cash flow approach

incorporating market

participant and

internally generated price assumptions

,

production profiles,

and operating and development cost

assumptions.

The fair values determined for

accounts receivable, accounts

payable, and most other current

assets and current

liabilities were equivalent to the carrying

value due to their short-term

nature.

The total consideration

of $

8.7

billion was allocated to the identifiable

assets and liabilities based on their fair values

at the acquisition date.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

94

Assets Acquired

Millions of Dollars

Accounts receivable, net

$

337

Inventories

20

Net properties, plants and equipment

8,624

Other assets

50

Total assets

acquired

$

9,031

Liabilities Assumed

Accounts payable

$

211

Accrued income and other taxes

6

Other accruals

20

Asset retirement obligations

and accrued environmental costs

86

Other liabilities and deferred credits

36

Total liabilities

assumed

$

359

Net assets acquired

$

8,672

With the completion of the Shell Permian transaction,

we acquired proved and unproved

properties of

approximately $

4.2

billion and $

4.4

billion, respectively.

We recognized approximately

$

44

million of transaction-

related costs which were expensed

during 2021.

Supplemental Pro Forma (unaudited)

The following tables summarize the

unaudited supplemental pro

forma financial information fo

r

the year ended

December 31, 2021, and 2020, as if we had completed the acquisitions

of Concho and the Shell Permian assets on

January 1, 2020.

Millions of Dollars

Year Ended December 31, 2021

Pro forma

Pro forma

As reported

Shell

Combined

Total

Revenues and Other Income

$

48,349

3,220

51,569

Income (loss) before income taxes

12,712

1,201

13,913

Net Income (Loss) attributable to

ConocoPhillips

8,079

920

8,999

Earnings per share:

Basic net loss

$

6.09

6.78

Diluted net loss

6.07

6.76

Millions of Dollars

Year Ended December 31, 2020

Pro forma

Pro forma

Pro forma

As reported

Concho

Shell

Combined

Total

Revenues and Other Income

$

19,256

3,762

1,685

24,703

Income (loss) before income taxes

(3,140)

787

(247)

(2,600)

Net Income (Loss) attributable to

ConocoPhillips

(2,701)

498

(189)

(2,392)

Earnings per share:

Basic net loss

$

(2.51)

(1.75)

Diluted net loss

(2.51)

(1.75)

Notes to Consolidated Financial Statements

95

ConocoPhillips

2021 10-K

The unaudited supplemental pro forma

financial information is presented

for illustration purposes

only and is not

necessarily indicative of the operating

results that would have occurred

had the transactions been completed on

January 1, 2020, nor is it necessarily indicative of future

operating results of the combined entity.

The unaudited

pro forma financial information

for the twelve-month period ending December 31, 2020

is a result of combining

the consolidated income statement

of ConocoPhillips with the results of Concho and the assets

acquired from

Shell.

The pro forma results do not

include transaction-related costs,

nor any cost savings anticipated

as a result of

the transactions.

The pro forma results include adjustments

from Concho's historical

results to reverse

impairment expense of $

10.5

billion and $

1.9

billion related to oil and gas properties

and goodwill, respectively.

Other adjustments made relate primarily to

DD&A, which is based on the unit-of-production

method, resulting

from the purchase price allocated

to properties, plants and equipment.

We believe the estimates

and assumptions

are reasonable, and the relative

effects of the transaction are

properly reflected.

Announced Acquisitions

In December 2021, we announced that we have

notified Origin Energy that we are exercising

our preemption right

to purchase an additional

10

percent shareholding interest

in APLNG from Origin Energy for $

1.645

billion, which

will be funded from cash on the balance sheet, before

customary adjustments.

The effective date of the

transaction will be July 1, 2020 with closing anticipated

to occur in the first quarter of 2022 subject

to Australian

government approval.

Note 4

and

Assets Sold

In 2020, we completed the sale of our Australia

-West asset and operations.

The sales agreement entitled us to a

$

200

million payment upon a final investment

decision (FID) of the Barossa development project.

On March 30,

2021, FID was announced and as such, we recognized

a $

200

million gain on disposition in the first quarter

of 2021.

The purchaser failed to pay the FID bonus

when due.

We have commenced an arbitration

proceeding against the

purchaser to enforce our contractual

right to the $

200

million, plus interest accruing from the due

date.

Results of

operations related to

this transaction are reflected in

our Asia Pacific segment.

See Note 11

In the second half of 2021, we sold our interests

in certain noncore assets in our Lower 48 segment for

approximately $

250

million after customary adjustments,

recognizing a before-tax gain

on sale of approximately

$

58

million.

We also completed the sale of our

noncore exploration

interests in Argentina,

recognizing a before-

tax loss on disposition of $

179

million.

Results of operations for

Argentina were reported

in our Other

International segment.

In 2021, we recorded contingent

payments of $

369

million relating to previous dispositions.

The contingent

payments are recorded

as gain on disposition on our consolidated

income statement and are

reflected within our

Canada and Lower 48 segments.

In our Canada segment, the

contingent payment, calculated and paid on a

quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price exceeds $52

CAD per barrel

The term for contingent

payments in our Canada segment ends on

May 16, 2022.

In our Lower 48

segment, the

contingent payment, paid on an annual basis, is calculated monthly at $7 million per month in which

the U.S. Henry Hub price is at or above $3.20 per MMBTU

The term for contingent payments

in our Lower 48

segment goes through 2023.

No

contingent payments were

recorded in 2020.

Planned Dispositions

In December 2021, we entered into

an agreement to sell two subsidiaries holding

our Indonesia assets and

operations to MedcoEnergi for

$

1.355

billion, before customary

adjustments, with an effective

date of January 1,

The subsidiaries hold our

54

percent interest in the Indonesia

Corridor Block Production Sharing Contract

(PSC) and a

35

percent shareholding interest

in the Transasia Pipeline

Company.

The net carrying value is

approximately $

0.4

billion, which consists primarily of PP&E.

The assets met the held for sale criteria in the fourth

quarter,

and as of December 31, 2021, we have reclassified

$

0.3

billion of PP&E to "Prepaid expenses and

other

current assets" and $

0.1

billion of noncurrent ARO to "Other accruals"

on our consolidated balance sheet.

The

before-tax earnings associated

with our Indonesia subsidiaries were $

604

million, $

394

million and $

512

million for

the years ended December 31, 2021, 2020 and 2019, respectively

This transaction is expected to close in

early

2022, subject to regulatory approvals

and other specific conditions precedent.

Results of operations for

the

subsidiaries to be sold are reported within our

Asia Pacific segment.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

96

In January 2022, we entered into

an agreement to sell our interests

in certain noncore assets in the Lower 48

segment for $

440

million, before customary adjustments.

This transaction is expected to

close in the second

quarter of 2022.

2020

Asset Acquisition

In August 2020, we completed the acquisition

of additional Montney acreage in Canada from Kelt

Exploration Ltd.

for $

382

million after customary adjustments,

plus the assumption of $

31

million in financing obligations

associated with partially owned infrastructure.

This acquisition consisted primarily of undeveloped

properties and

included

140,000

net acres in the liquids-rich Inga Fireweed

asset Montney zone, which is directly

adjacent to our

existing Montney position.

The transaction increased our Montney acreage

position to approximately

295,000

net

acres with a

100

percent working interest.

This agreement was accounted

for as an asset acquisition resulting

in

the recognition of $

490

million of PP&E; $

77

million of ARO and accrued environmental

costs; and $

31

million of

financing obligations recorded

primarily to long-term debt.

Results of operations for

the Montney asset are

reported in our Canada segment.

Assets Sold

In February 2020, we sold our Waddell Ranch

interests in the Permian Basin

for $

184

million after customary

adjustments.

No

gain or loss was recognized on the sale.

Results of operations for

the Waddell Ranch interests

sold were reported in our Lower 48 segment.

In March 2020, we completed the sale

of our Niobrara interests

for approximately $

359

million after customary

adjustments and recognized a

before-tax loss on disposition

of $

38

million.

At the time of disposition, our interest

in Niobrara had a net carrying value

of $

397

million, consisting primarily of $

433

million of PP&E and $

34

million of

ARO. The before-tax losses

associated with our interests

in Niobrara, including the loss on disposition

noted above

and an impairment of $

386

million recorded when we signed an

agreement to sell our interests

in the fourth

quarter of 2019, were $

25

million and $

372

million for the years ended December 31,

2020 and 2019, respectively.

Results of operations for

the Niobrara interests

sold were reported in our Lower 48 segment.

In May 2020, we completed the divestiture

of our subsidiaries that held our Australia

-West assets and operations,

and based on an effective date

of January 1, 2019, we received proceeds

of $

765

million.

We recognized a

before-

tax gain of $

587

million related to this transaction

in 2020.

At the time of disposition, the net carrying value

of the

subsidiaries sold was approximately

$

0.2

billion, excluding $

0.5

billion of cash.

The net carrying value consisted

primarily of $

1.3

billion of PP&E and $

0.1

billion of other current assets offset

by $

0.7

billion of ARO, $

0.3

billion of

deferred tax liabilities, and

$

0.2

billion of other liabilities.

The before-tax earnings associated

with the subsidiaries

sold, including the gain on disposition noted

above, were $

851

million and $

372

million for the years ended

December 31, 2020 and 2019, respectively.

Production from the beginning of the year through

the disposition

date in May 2020 averaged

43

MBOED.

The sales agreement entitled us to

an additional $

200

million upon FID of

the Barossa development project.

Results of operations for

the subsidiaries sold were reported

in our Asia Pacific

segment.

2019

Assets Sold

In January 2019, we entered into

agreements to sell our

12.4

percent ownership interests

in the Golden Pass LNG

Terminal and

Golden Pass Pipeline.

We also entered into

agreements to amend our contractual

obligations for

retaining use of the facilities.

As a result of entering into these agreements,

we recorded a before

-tax impairment

of $

60

million in the first quarter of 2019 which is

included in the "Equity in earnings of affiliates"

line on our

consolidated income statement.

We completed the sale in the second

quarter of 2019.

Results of operations for

these assets were reported in our Lower

48 segment.

Notes to Consolidated Financial Statements

97

ConocoPhillips

2021 10-K

In April 2019, we entered into

an agreement to sell two ConocoPhillips

U.K. subsidiaries to Chrysaor E&P Limited

for $

2.675

billion plus interest and customary

adjustments, with an effective date

of January 1, 2018.

On

September 30, 2019, we completed the sale

for proceeds of $

2.2

billion and recognized a $

1.7

billion before-tax

and $

2.1

billion after-tax gain

associated with this transaction in 2019.

Together the

subsidiaries sold indirectly

held our exploration and production

assets in the U.K.

At the time of disposition, the net carrying value

was

approximately $

0.5

billion, consisting primarily of $

1.6

billion of PP&E, $

0.5

billion of cumulative foreign currency

translation adjustments, and $

0.3

billion of deferred tax assets,

offset by $

1.8

billion of ARO and negative $

0.1

billion of working capital.

The before-tax earnings associated

with the subsidiaries sold, including the gain on

dispositions noted above, was $

2.1

billion for the year ended December 31, 2019.

Results of operations for

the

U.K. were reported within our Europe,

Middle East and North Africa segment.

In the second quarter of 2019, we recognized

an after-tax gain

of $

52

million upon the closing of the sale of our

30

percent interest in the Greater

Sunrise Fields to the government of Timor-Leste

for $

350

million.

The Greater

Sunrise Fields were included in our Asia Pacific

segment.

In the fourth quarter of 2019, we sold our interests

in the Magnolia field and platform for

net proceeds of $

16

million and recognized a before-tax

gain of $

82

million.

At the time of sale, the net carrying value

consisted of $

4

million of PP&E offset by $

70

million of ARO.

The Magnolia results of operations

were reported within our Lower

48 segment.

Note 4-Investments,

Loans and Long-Term

Receivables

Components of investments, loans

and long-term receivables at December 31 were:

Millions of Dollars

2021

2020

Equity investments

$

6,701

7,596

Loans and advances-related parties

114

Long-term receivables

98

137

Long-term investments in debt

securities

248

217

Other investments

66

67

$

7,113

8,131

Equity Investments

Affiliated companies in which we had a significant

equity investment at December 31, 2021,

included:

●

APLNG-

37.5

percent owned joint venture

with Origin Energy (

37.5

percent) and Sinopec (

25

percent)-

to produce CBM from the Bowen and

Surat basins in Queensland, Australia,

as well as process and export

LNG.

●

Qatar Liquefied Gas Company Limited

(3) (QG3)-

30

percent owned joint venture

with affiliates of

QatarEnergy (

68.5

percent) and Mitsui & Co., Ltd. (

1.5

percent)-produces and liquefies

natural gas from

Qatar's North Field, as well as exports

LNG.

Summarized 100 percent earnings

information for equity method

investments in affiliated

companies,

combined, was as follows:

Millions of Dollars

2021

2020

2019

Revenues

$

11,824

7,931

11,310

Income before income taxes

3,946

1,843

3,726

Net income

2,557

1,426

3,085

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

98

Summarized 100 percent balance sheet information

for equity method investments

in affiliated companies,

combined, was as follows:

Millions of Dollars

2021

2020

Current assets

$

4,493

2,579

Noncurrent assets

36,602

35,257

Current liabilities

3,498

2,110

Noncurrent liabilities

17,465

18,099

Our share of income taxes incurred

directly by an equity method investee

is reported in equity in earnings of

affiliates, and as such is not included in income taxes

on our consolidated financial statements.

At December 31, 2021, retained earnings

included $

42

million related to the undistributed

earnings of affiliated

companies.

Dividends received from affiliates

were $

1,279

million, $

1,076

million and $

1,378

million in 2021, 2020

and 2019, respectively.

APLNG

APLNG is a joint venture focused on

producing CBM from the Bowen and Surat

basins in Queensland, Australia.

Natural gas is sold to domestic

customers and LNG is processed

and exported to Asia Pacific markets.

Our

investment in APLNG gives us access

to CBM resources in Australia

and enhances our LNG position.

The majority

of APLNG LNG is sold under two long-term sales and purchase

agreements, supplemented with sales

of additional

LNG spot cargoes targeting

the Asia Pacific markets.

Origin Energy,

an integrated Australian

energy company,

is

the operator of APLNG's

production and pipeline system,

while we operate the LNG facility.

APLNG executed project financing

agreements for an $

8.5

billion project finance facility in 2012.

All amounts were

drawn from the facility.

APLNG achieved financial completion on its original

$

8.5

billion project finance facility

during the third quarter of 2017, resulting in the facility

being nonrecourse.

The project financing facility has been

refinanced over time and at December 31, 2021, this

facility was composed of a financing agreement

with the

Export-Import Bank of the United States,

a commercial bank facility and

two

United States Private

Placement note

facilities.

APLNG made its first principal and interest

repayment in March 2017 and is scheduled to

make

bi-annual

payments until September 2030.

At December 31, 2021, a balance of $

5.7

billion was outstanding on the facilities.

See Note 10

During the fourth quarter of 2021, Origin Energy Limited

agreed to the sale of

10

percent of their interest in

APLNG

for $

1.645

billion, before customary

adjustments.

ConocoPhillips announced in December 2021 that we were

exercising our preemption

right under the APLNG Shareholders Agreement

to purchase an additional

10

percent

shareholding interest in APLNG, subject

to government approvals.

The sales price associated with this preemption

right was determined to reflect

a relevant observable market

participant view of APLNG's

fair value which was

below the carrying value of our existing

investment in APLNG.

Based on a review of the facts and circumstances

surrounding this decline in fair value,

we concluded in the fourth quarter of 2021 the impairment

was other than

temporary under the guidance of FASB

ASC Topic 323,

and the recognition of an impairment of our existing

investment was necessary.

Accordingly,

we recorded a noncash $

688

million, before-tax and

after-tax impairment

in the fourth quarter of 2021.

The impairment, which is included in the "Impairments" line on

our consolidated

income statement, had the

effect of reducing the carrying value

of our existing investment

to $

5,574

million as of

December 31, 2021.

This carrying value is included in the "Investments

and long-term receivables" line on our

consolidated balance sheet.

See Note 7

Notes to Consolidated Financial Statements

99

ConocoPhillips

2021 10-K

The historical cost basis of our

37.5

percent share of net assets on the books

of APLNG was $

5,523

million,

resulting in a basis difference of $

51

million on our books.

The basis difference, which is substantially

all

associated with PP&E and subject to amortization,

has been allocated on a relative

fair value basis to individual

production license areas owned by APLNG.

Any future additional payments

are expected to be allocated

in a

similar manner.

As the joint venture produces

natural gas from each license, we amortize

the basis difference

allocated to that license using the unit-of-production

method.

Included in net income (loss) attributable

to

ConocoPhillips for 2021, 2020 and 2019 was

after-tax expense

of $

39

million, $

41

million and $

36

million,

respectively,

representing the amortization

of this basis difference on currently

producing licenses.

QG3

QG3 is a joint venture that owns an

integrated large-scale

LNG project located in Qatar.

We provided project

financing, with a current outstanding balance of $

114

million as described below under "Loans."

At December 31,

2021, the book value of our equity method investment

in QG3, excluding the project financing, was

$

736

million.

We have terminal and pipeline

use agreements with Golden Pass

LNG Terminal and affiliated

Golden Pass Pipeline

near Sabine Pass, Texas,

intended to provide us with terminal and

pipeline capacity for the receipt, storage

and

regasification of LNG purchased

from QG3.

We previously held a

12.4

percent interest in Golden

Pass LNG

Terminal and

Golden Pass Pipeline, but we sold those interests

in the second quarter of 2019 while retaining the

basic use agreements.

Currently,

the LNG from QG3 is being sold to markets

outside of the U.S.

Loans

As part of our normal ongoing business operations

and consistent with industry practice,

we enter into numerous

agreements with other parties to pursue

business opportunities.

Included in such activity are loans to certain

affiliated and non-affiliated

companies.

At December 31, 2021, significant loans

to affiliated companies include $

114

million in project financing to QG3

which is recorded within the "Accounts

and notes receivable-related

parties" line on our consolidated balance

sheet.

QG3 secured project financing of $

4.0

billion in December 2005, consisting of $

1.3

billion of loans from

export credit agencies (ECA), $

1.5

billion from commercial banks

and $

1.2

billion from ConocoPhillips.

The

ConocoPhillips loan facilities have

substantially the same terms as the ECA

and commercial bank facilities.

On

December 15, 2011, QG3 achieved financial completion

and all project loan facilities became nonrecourse

to the

project participants.

Semi-annual

repayments began in January 2011 and

will extend through July 2022.

Note 5-Investment in Cenovus

Energy

Our investment in Cenovus Energy

(CVE) common shares is carried on our balance sheet

at fair value.

December 31

2021

2020

Number of shares of CVE common stock (millions)

91

208

Ownership of issued and outstanding common

stock

4.5

%

16.9

Closing price on NYSE on last trading day

($/share)

$

12.28

6.04

Fair Value (millions

of dollars)

$

1,117

1,256

During 2021, we began to dispose of CVE shares,

selling

117

million shares during the year,

recognizing proceeds of

$

1.18

billion, $

1.14

billion of which was received during the year.

Proceeds related to the sale of our

CVE shares

are presented within "Cash Flows from

Investing Activities" on our consolidated

statement of cash flows.

Subject

to market conditions, we intend

to continue to decrease our investment.

All gains and losses are recognized

within "Other income (loss)" on our consolidated

income statement.

See Note

13

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

100

Millions of Dollars

2021

2020

2019

Total

Net gain (loss) on equity securities

$

1,040

(855)

649

Less: Net gain (loss) on equity securities sold during

the period

473

Unrealized gain (loss) on equity securities

still held at

the reporting date

$

567

(855)

649

Note 6-Suspended Wells and

Exploration Expenses

The following table reflects the net

changes in suspended exploratory

well costs during 2021, 2020 and 2019:

Millions of Dollars

2021

2020

2019

Beginning balance at January 1

$

682

1,020

856

Additions pending the determination of proved

reserves

10

164

239

Reclassifications to proved

properties

(42)

(11)

Sales of suspended wells

(313)

(54)

Charged to dry hole expense

(32)

(147)

(10)

Ending balance at December 31

$

660

682

1,020

*Includes $

313

million of assets held for sale in Australia-West at December 31, 2019.

For additional details on suspended wells charged to dry hole expense, see the Exploration Expenses section

of this Note.

The following table provides an aging

of suspended well balances at December 31:

Millions of Dollars

2021

2020

2019

Exploratory well costs capitalized

for a period of one year or less

$

4

156

206

Exploratory well costs capitalized

for a period greater than one year

656

526

814

Ending balance

$

660

682

1,020

*Includes $

313

million of assets held for sale in Australia-West at December 31, 2019.

Number of projects with exploratory

well costs capitalized for

a period

greater than one year

22

22

23

Notes to Consolidated Financial Statements

101

ConocoPhillips

2021 10-K

The following table provides a further

aging of those exploratory

well costs that have been capitalized

for more

than one year since the completion of drilling as of December 31, 2021:

Millions of Dollars

Suspended Since

Total

2018-2020

2015-2017

2004-2014

Willow-Alaska

(1)

313

262

51

Surmont-Canada

(1)

121

2

19

100

PL 1009-Norway

(1)

43

43

PL 891-Norway

(1)

34

34

Narwhal Trend-Alaska

(1)

25

25

WL4-00-Malaysia

(1)

24

24

PL782S-Norway

(1)

22

22

NC 98-Libya

(2)

13

13

Other of $10 million or less each

(1)(2)

61

21

11

29

Total

$

656

433

81

142

(1)Additional appraisal wells planned.

(2)Appraisal drilling complete; costs being incurred to assess development.

Exploration Expenses

The charges discussed below are included in the "Exploration

expenses" line on our consolidated income

statement.

2020

In our Alaska segment, we recorded

a before-tax impairment

of $

828

million for the entire associated

carrying

value of capitalized undeveloped

leasehold costs related to

our Alaska North Slope Gas asset.

We no longer

believe the project will advance,

and there is no current market

for the asset.

In our Other International segment, our interests

in the Middle Magdalena Basin of Colombia are in force

majeure.

As we had no immediate plans to perform

under existing contracts;

therefore, in 2020, we recorded

a before-tax

expense totaling $

84

million for dry hole costs of a previously

suspended well and an impairment of the associated

capitalized undeveloped leasehold

carrying value.

In our Asia Pacific segment, we recorded

before-tax expense

of $

50

million related to dry hole costs

of a previously

suspended well and an impairment of the associated capitalized

undeveloped leasehold carrying value associated

with the Kamunsu East Field in Malaysia

that is no longer in our development plans.

2019

In our Lower 48 segment, we recorded

a before-tax impairment

of $

141

million for the associated carrying value

of

capitalized undeveloped leasehold

costs and dry hole expenses of $

111

million before-tax

due to our decision to

discontinue exploration

activities related to our Central Louisiana

Austin Chalk acreage.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

102

Note 7-Impairments

During 2021, 2020 and 2019, we recognized the following

before-tax impairment

charges:

Millions of Dollars

2021

2020

2019

Alaska

$

5

Lower 48

(8)

804

402

Canada

6

3

2

Europe, Middle East and North Africa

(24)

6

1

Asia Pacific

695

$

674

813

405

2021

We recorded an impairment

of $

688

million on our APLNG investment included within

the Asia Pacific segment.

Note 4

and

Note 13

In our Lower 48 segment, we recorded

a credit to impairment of $

89

million due to a decreased ARO estimate

for a

previously sold asset, in which we retained

the ARO liability.

This was offset by recorded

impairments of $

84

million during the fourth quarter of 2021, related

to certain noncore assets

due to changes in development plans.

See Note 13

In our Europe, Middle East and North

Africa segment, we recorded a credit

to impairment of $

24

million due to

decreased ARO estimates on fields

in Norway which ceased production and

were fully depreciated in prior years.

2020

We recorded impairments

of $

813

million, primarily related to certain

noncore assets in the Lower 48.

Due to a

significant

decrease in the outlook for current and

long-term natural gas prices

in early 2020, we recorded

impairments of $

523

million, primarily for the Wind River Basin operations

area, consisting of developed

properties in the Madden Field and the Lost Cabin

Gas Plant, in the first quarter of 2020.

Additionally,

due

primarily to changes in development plans

solidified in the last quarter of 2020, we recognized

additional

impairments of $

287

million in the Lower 48 during the fourth

quarter.

See Note 13

2019

In the Lower 48, we recorded impairments

of $

402

million, primarily related to developed

properties in our

Niobrara asset which were written

down to fair value less costs

to sell.

Note 8-Asset Retirement

Obligations and Accrued Environmental

Costs

Asset retirement obligations

and accrued environmental costs

at December 31 were:

Millions of Dollars

2021

2020

Asset retirement obligations

$

5,926

5,573

Accrued environmental costs

187

180

Total

asset retirement obligations

and accrued environmental costs

6,113

5,753

Asset retirement obligations

and accrued environmental costs

due within one year*

(359)

(323)

Long-term asset retirement obligations

and accrued environmental costs

$

5,754

5,430

*Classified as a current liability on the balance sheet under "Other accruals."

Notes to Consolidated Financial Statements

103

ConocoPhillips

2021 10-K

Asset Retirement Obligations

We record the fair value

of a liability for an ARO when it is incurred (typically

when the asset is installed at the

production location).

When the liability is initially recorded, we capitalize

the associated asset retirement

cost by

increasing the carrying amount of the related

PP&E.

If, in subsequent

periods, our estimate of this liability

changes, we will record an adjustment

to both the liability and PP&E.

Over time, the liability increases for the

change in its present value, while the capitalized

cost depreciates over

the useful life of the related asset.

Reductions to estimated liabilities

for assets that are no longer producing

are recorded as a credit to

impairment, if

the asset had been previously impaired, or as a credit

to DD&A, if the asset had not been previously impaired

We have numerous

AROs we are required to perform

under law or contract once an asset is permanently

taken

out of service.

Most of these obligations are not

expected to be paid until several

years, or decades, in the future

and will be funded from general company

resources at the time of removal.

Our largest individual obligations

involve plugging and abandonment of wells and

removal and disposal of offshore

oil and gas platforms around

the

world, as well as oil and gas production

facilities and pipelines in Alaska.

During 2021 and 2020, our overall ARO changed as

follows:

Millions of Dollars

2021

2020

Balance at January 1

$

5,573

6,206

Accretion of discount

238

248

New obligations

555

262

Changes in estimates of existing

obligations

(113)

(307)

Spending on existing obligations

(164)

(116)

Property dispositions

(108)

(771)

Foreign currency translation

(55)

51

Balance at December 31

$

5,926

5,573

Accrued Environmental Costs

Total

accrued environmental costs

at December 31, 2021 and 2020, were $

187

million and $

180

million,

respectively.

We had accrued environmental

costs of $

135

million and $

116

million at December 31, 2021 and 2020,

respectively,

related to remediation

activities in the U.S. and Canada.

We had also accrued in Corporate

and Other

$

36

million and $

48

million of environmental costs

associated with sites no longer in operation

at December 31,

2021 and 2020, respectively.

In addition, both December 31, 2021 and 2020, included a $

16

million accrual, where

the company has been named a potentially

responsible party under the Federal Comprehensive

Environmental

Response, Compensation and Liability Act, or similar state

laws.

Accrued environmental liabilities are

expected to

be paid over periods extending up to

30

years.

Expected expenditures for environmental

obligations acquired in various

business combinations are discounted

using a weighted-average

5

percent discount factor,

resulting in an accrued balance for acquired

environmental

liabilities of $

109

million at December 31, 2021.

The total expected future undiscounted

payments related to the

portion of the accrued environmental costs

that have been discounted

are $

153

million.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

104

Note 9-Debt

Long-term debt at December 31 was:

Millions of Dollars

2021

2020

9.125

% Debentures due 2021

$

123

2.4

% Notes due 2022

329

329

7.65

% Debentures due 2023

78

78

3.35

% Notes due 2024

426

426

8.2

% Debentures due 2025

134

134

3.35

% Notes due 2025

199

199

6.875

% Debentures due 2026

67

67

4.95

% Notes due 2026

1,250

1,250

7.8

% Debentures due 2027

203

203

3.75

% Notes due 2027

981

3.75

% Notes due 2027

19

4.3

% Notes due 2028

973

4.3

% Notes due 2028

27

7.375

% Debentures due 2029

92

92

7

% Debentures due 2029

200

200

6.95

% Notes due 2029

1,549

1,549

8.125

% Notes due 2030

390

390

2.4

% Notes due 2031

489

2.4

% Notes due 2031

11

7.2

% Notes due 2031

575

575

7.25

% Notes due 2031

500

500

7.4

% Notes due 2031

500

500

5.9

% Notes due 2032

505

505

4.15

% Notes due 2034

246

246

5.95

% Notes due 2036

500

500

5.951

% Notes due 2037

645

645

5.9

% Notes due 2038

600

600

6.5

% Notes due 2039

2,750

2,750

4.3

% Notes due 2044

750

750

5.95

% Notes due 2046

500

500

7.9

% Debentures due 2047

60

60

4.875

% Notes due 2047

800

4.85

% Notes due 2048

590

4.85

% Notes due 2048

10

Floating rate notes due 2022 at

1.02

% -

1.12

% during 2021 and

1.12

% -

2.81

% during 2020

500

500

Marine Terminal

Revenue Refunding Bonds due 2031 at

0.04

% -

0.15

% during

2021 and

0.1

% -

7.5

% during 2020

265

265

Industrial Development Bonds due 2035 at

0.04

% -

0.12

% during 2021 and

0.11

% -

7.5

% during 2020

18

18

Commercial Paper at

0.05

% -

0.22

% during 2021

300

Other

35

38

Debt at face value

17,766

14,292

Finance leases

1,261

891

Net unamortized premiums, discounts and debt

issuance costs

907

186

Total

debt

19,934

15,369

Short-term debt

(1,200)

(619)

Long-term debt

$

18,734

14,750

Notes to Consolidated Financial Statements

105

ConocoPhillips

2021 10-K

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, with an outstanding principal balance

of $

3.9

billion, which was recorded

at fair value of $

4.7

billion on the acquisition date.

The adjustment to fair value of the senior notes

of

approximately $

0.8

billion on the acquisition date will be amortized as

an adjustment to interest

expense over the

remaining contractual terms

of the senior notes.

In the first quarter of 2021, we completed

a debt exchange offer

related to the debt assumed from

Concho.

Of the

approximately $

3.9

billion in aggregate principal amount

of Concho's senior notes

offered in the exchange,

98

percent, or approximately

$

3.8

billion, was tendered and accepted.

The new debt issued by ConocoPhillips had

the same interest rates

and maturity dates as the Concho senior notes.

The portion not exchanged, approximately

$

67

million, remained outstanding across

five series of senior notes issued by Concho.

The debt exchange was

treated as a debt modification for

accounting purposes resulting in a portion

of the unamortized fair value

adjustment of the Concho senior notes allocated

to the new debt issued by ConocoPhillips on the settlement

date

of the exchange.

The new debt issued in the exchange is

fully and unconditionally guaranteed by

ConocoPhillips

Company.

We have a revolving

credit facility totaling $

6.0

billion with an expiration date

of May 2023.

Our revolving credit

facility may be used for direct

bank borrowings, the issuance of letters

of credit totaling up to $

500

million, or as

support for our commercial paper program.

The revolving credit facility is broadly

syndicated among financial

institutions and does not contain any

material adverse change provisions

or any covenants requiring maintenance

of specified financial ratios or credit ratings.

The facility agreement contains

a cross-default provision

relating to

the failure to pay principal or

interest on other debt obligations

of $

200

million or more by ConocoPhillips, or any

of its consolidated subsidiaries.

The amount of the facility is not subject to redetermination

prior to its expiration

date.

Credit facility borrowings may

bear interest at a margin above

rates offered

by certain designated banks in the

London interbank market or

at a margin above the overnight federal

funds rate or prime rates

offered by certain

designated banks in the U.S.

The facility agreement calls for

commitment fees on available,

but unused, amounts.

The 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

our ability to issue up to $

6.0

billion of commercial paper,

which 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

of credit, we had access to

$

6.0

billion in available borrowing capacity

under our revolving credit facility

at December 31, 2021.

We had

no

direct borrowings, letters

of credit, and $

300

million of commercial paper outstanding

as of December 31, 2020.

For information on Finance Leases,

see Note 15

The current credit ratings on our

long-term debt are:

●

Fitch: "A" with a "stable" outlook

●

S&P: "A-" with a "stable" outlook

●

Moody's: "A3" with a "positive" 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 the

commercial paper markets.

If our credit rating were to

deteriorate to a level

prohibiting us from accessing the

commercial paper market, we

would still be able to access funds under our revolving

credit facility.

At both December 31, 2021 and 2020, we had $

283

million of certain variable rate

demand bonds (VRDBs)

outstanding with maturities ranging

through 2035.

The VRDBs are redeemable at the option of the bondholders

on any business day.

If they are ever redeemed, we have

the ability and intent to refinance on

a long-term basis,

therefore, the VRDBs are included

in the "Long-term debt" line on our consolidated balance sheet.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

106

Note 10-Guarantees

At December 31, 2021, we were liable for

certain contingent obligations

under various contractual arrangements

as described below.

We recognize a liability,

at inception, for the fair value

of our obligation as a guarantor

for

newly issued or modified guarantees.

Unless the carrying amount of the liability is noted below,

we have not

recognized a liability because the

fair value of the obligation

is immaterial.

In addition, unless otherwise stated, we

are not currently performing with any

significance under the guarantee and expect

future performance to be

either immaterial or have only a remote

chance of occurrence.

APLNG Guarantees

At December 31, 2021, we had outstanding

multiple guarantees in connection with our

37.5

percent ownership

interest in APLNG.

The following is a description of the guarantees

with values calculated utilizing December 2021

exchange rates:

●

During the third quarter of 2016, we issued a guarantee

to facilitate the withdrawal

of our pro-rata

portion of the funds in a project finance reserve account.

We estimate the remaining

term of this

guarantee to be

9

years.

Our maximum exposure under this guarantee

is approximately $

170

million and

may become payable if an enforcement

action is commenced by the project finance lenders

against

APLNG.

At December 31, 2021, the carrying value of this

guarantee is approximately

$

14

million.

●

In conjunction with our original purchase of an ownership

interest in APLNG from Origin Energy

in

October 2008, we agreed to reimburse

Origin Energy for our share of the existing

contingent liability

arising under guarantees of an existing

obligation of APLNG to deliver natural

gas under several sales

agreements.

The final guarantee expires

in the fourth quarter of 2041.

Our maximum potential liability

for future payments, or cost

of volume delivery, under

these guarantees is estimated

to be $

660

million

($

1.2

billion in the event of intentional

or reckless breach) and would become payable

if APLNG fails to

meet its obligations under these agreements

and the obligations cannot otherwise be mitigated.

Future

payments are considered unlikely,

as the payments, or cost of volume delivery,

would only be triggered if

APLNG does not have enough natural

gas to meet these sales commitments and

if the co-ventures do not

make necessary equity contributions

into APLNG.

●

We have guaranteed

the performance of APLNG with regard

to certain other contracts

executed in

connection with the project's continued

development.

The guarantees have

remaining terms of

15 to 24

years

or the life of the venture.

Our maximum potential amount of future payments

related to these

guarantees is approximately

$

180

million and would become payable

if APLNG does not perform.

At

December 31, 2021, the carrying value of these guarantees

was approximately $

11

million.

Other Guarantees

We have other guarantees

with maximum future potential payment

amounts totaling approximately

$

720

million,

which consist primarily of guarantees

of the residual value of leased office buildings, guarantees

of the residual

value of corporate aircraft,

and a guarantee for our portion

of a joint venture's

project finance reserve accounts.

These guarantees have remaining

terms of

one to five years

and would become payable if certain asset

values are

lower than guaranteed amounts

at the end of the lease or contract term, business

conditions decline at

guaranteed entities, or as a result

of nonperformance of contractual

terms by guaranteed parties.

At

December 31, 2021, the carrying value of these guarantees

was approximately $

8

million.

Indemnifications

Over the years, we have entered

into agreements to sell ownership

interests in certain legal

entities, joint ventures

and assets that gave rise to

qualifying indemnifications.

These agreements include indemnifications for

taxes and

environmental liabilities.

The carrying amount recorded for

these indemnifications at December 31, 2021, was

approximately $

20

million.

Those related to environmental

issues have terms that are generally

indefinite and the

maximum amounts

of future payments are generally

unlimited.

Although it is reasonably possible future

payments may exceed

amounts recorded, due to

the nature of the indemnifications, it is not possible to

make a

reasonable estimate of the maximum potential

amount of future payments.

See Note 11

for additional

information about environmental

liabilities.

Notes to Consolidated Financial Statements

107

ConocoPhillips

2021 10-K

Note 11-Contingencies and Commitments

A number of lawsuits involving a variety

of claims arising in the ordinary course of business

have been filed against

ConocoPhillips.

We also may be required

to remove or mitigate

the effects on the environment

of the placement,

storage, disposal or release of

certain chemical, mineral and petroleum

substances at various

active and inactive

sites.

We regularly assess the need for accounting

recognition or disclosure of these contingencies.

In the case of

all known contingencies (other than those related

to income taxes), we accrue

a liability when the loss is probable

and the amount is reasonably estimable.

If a range of amounts can be reasonably

estimated and no amount within

the range is a better estimate

than any other amount, then the low end of the range

is accrued.

We do not reduce

these liabilities for potential insurance

or third-party recoveries.

We accrue receivables for

insurance or other

third-party recoveries when applicable.

With respect to income tax-related

contingencies, we use a cumulative

probability-weighted loss

accrual in cases where sustaining a tax

position is less than certain.

See Note 17

,

for

additional information about income tax

-related contingencies.

Based on currently available information,

we believe it is remote that future

costs related to known

contingent

liability exposures will exceed

current accruals by an amount that

would have a material adverse

impact on our

consolidated financial statements.

As we learn new facts concerning contingencies,

we reassess our position both

with respect to accrued liabilities and other potential

exposures.

Estimates particularly sensitive to future

changes

include contingent liabilities recorded

for environmental

remediation, tax and legal matters.

Estimated future

environmental remediation

costs are subject to change due to

such factors as the uncertain

magnitude of cleanup

costs, the unknown time and extent of such

remedial actions that may be required,

and the determination of our

liability in proportion to that of other responsible

parties.

Estimated future costs

related to tax and legal

matters

are subject to change as events

evolve and as additional information

becomes available during the administrative

and litigation processes.

Environmental

We are subject to international,

federal, state and

local environmental laws

and regulations and record

accruals for

environmental liabilities based on

management's best estimates

These estimates are based on currently

available

facts, existing technology,

and presently enacted laws and regulations,

taking into account stakeholder

and

business considerations.

When measuring environmental liabilities,

we also consider our prior experience in

remediation of contaminated

sites, other companies' cleanup experience, and data

released by the U.S. EPA

or

other organizations.

We consider unasserted claims in our determination

of environmental liabilities,

and we

accrue them in the period they are both probable and

reasonably estimable.

Although liability of those potentially responsible

for environmental remediation

costs is generally joint and

several for federal

sites and frequently so for other

sites, we are usually only one of many companies

cited at a

particular site.

Due to the joint and several liabilities, we could

be responsible for all cleanup costs related

to any

site at which we have been designated

as a potentially responsible party.

We have been successful to

date in

sharing cleanup costs with other financially sound

companies.

Many of the sites at which we are potentially

responsible are still under investigation

by the EPA or

the agency concerned.

Prior to actual cleanup, those

potentially responsible normally assess the

site conditions, apportion responsibility and determine

the appropriate

remediation.

In some instances, we may have

no liability or may attain a settlement

of liability.

Where it appears

that other potentially responsible parties may

be financially unable to bear their proportional share,

we consider

this inability in estimating our potential liability,

and we adjust our accruals accordingly.

As a result of various

acquisitions in the past, we assumed certain environmental

obligations.

Some of these environmental obligations

are mitigated by indemnifications

made by others for our benefit, and some of the indemnifications

are subject to

dollar limits and time limits.

We are currently participating

in environmental assessments

and cleanups at numerous federal

Superfund and

comparable state and

international sites.

After an assessment of environmental

exposures for cleanup and other

costs, we make accruals on an

undiscounted basis (except

those acquired in a purchase business combination,

which we record on a discounted

basis) for planned investigation

and remediation activities for sites where

it is

probable future costs will be incurred

and these costs can be reasonably estimated.

We have not reduced

these

accruals for possible insurance recoveries.

In the future, we may be involved

in additional environmental

assessments, cleanups and proceedings.

Note 8

,

for a summary of our accrued environmental

liabilities.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

108

Litigation and Other Contingencies

We are subject to various

lawsuits and claims including but not limited to matters

involving oil and gas royalty

and

severance tax payments,

gas measurement and valuation

methods, contract disputes,

environmental damages,

climate change, personal injury,

and property damage.

Our primary exposures for such matters

relate to alleged

royalty and tax underpayments

on certain federal, state

and privately owned properties,

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 mediation.

Based on

professional judgment and experience

in using these litigation management

tools and available information

about

current developments in all our cases,

our legal organization regularly

assesses the adequacy of current accruals

and determines if adjustment of existing

accruals, or establishment of new accruals, is

required.

We have contingent

liabilities resulting from throughput agreements

with pipeline and processing companies not

associated with financing arrangements.

Under these agreements, we may be required

to provide any such

company with additional funds through

advances and penalties for fees related

to throughput capacity not utilized.

In addition, at December 31, 2021, we had performance

obligations secured by letters

of credit of $

337

million (issued as direct bank letters of credit)

related to various

purchase commitments for materials,

supplies,

commercial activities and services incident to the ordinary

conduct of business.

In 2007, ConocoPhillips was unable to reach

agreement with respect to the empresa

mixta structure mandated

by

the Venezuelan government's

Nationalization Decree.

As a result, Venezuela's

national oil company,

Petróleos de

Venezuela, S.A. (PDVSA),

or its affiliates, directly assumed control

over ConocoPhillips' interests

in the Petrozuata

and Hamaca heavy oil ventures and

the offshore Corocoro development

project.

In response to this expropriation,

ConocoPhillips initiated international

arbitration on November 2, 2007, with the ICSID.

On September 3, 2013, an

ICSID arbitration tribunal held that Venezuela

unlawfully expropriated ConocoPhillips'

significant oil investments in

June 2007.

On January 17, 2017, the Tribunal reconfirmed

the decision that the expropriation

was unlawful.

In

March 2019, the Tribunal unanimously

ordered the government of Venezuela

to pay ConocoPhillips approximately

$

8.7

billion in compensation for the government's

unlawful expropriation of the company's

investments in

Venezuela in 2007.

On August 29, 2019, the ICSID Tribunal

issued a decision rectifying the award and

reducing it

by approximately $

227

million.

The award now stands at

$

8.5

billion plus interest.

The government of Venezuela

sought annulment of the award,

which automatically stayed

enforcement of the award.

On September 29, 2021,

the ICSID annulment committee lifted the

stay of enforcement

of the award.

The annulment proceedings have

been suspended as a result of Venezuela's

non-payment of advances

to cover the costs of these proceedings.

In 2014, ConocoPhillips filed a separate

and independent arbitration under the rules

of the ICC against PDVSA

under the contracts that had established

the Petrozuata

and Hamaca projects.

The ICC Tribunal issued

an award in

April 2018, finding that PDVSA owed ConocoPhillips

approximately $

2

billion under their agreements in connection

with the expropriation of the projects

and other pre-expropriation fiscal

measures.

In August 2018, ConocoPhillips

entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the

payment period, including initial payments totaling approximately $500 million within a period of 90 days from the

time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of

four and a half years.

Per the settlement, PDVSA recognized

the ICC award as a judgment in various

jurisdictions,

and ConocoPhillips agreed to suspend

its legal enforcement actions.

ConocoPhillips sent notices of default to

PDVSA on October 14 and November 12, 2019, and

to date PDVSA has failed to

cure its breach.

As a result,

ConocoPhillips has resumed legal enforcement

actions.

To date,

ConocoPhillips has received approximately

$

768

million in connection with the ICC award.

ConocoPhillips has ensured that

the settlement and any actions taken

in

enforcement thereof meet all

appropriate U.S. regulatory

requirements, including those related

to any applicable

sanctions imposed by the U.S. against

Venezuela.

Notes to Consolidated Financial Statements

109

ConocoPhillips

2021 10-K

In 2016, ConocoPhillips filed a separate

and independent arbitration under the rules

of the ICC against PDVSA

under the contracts that had established

the Corocoro Project.

On August 2, 2019, the ICC Tribunal

awarded

ConocoPhillips approximately

$

33

million plus interest under the Corocoro

contracts.

ConocoPhillips is seeking

recognition and enforcement

of the award in various jurisdictions.

ConocoPhillips has ensured that all the actions

related to the award meet

all appropriate U.S. regulatory

requirements, including those related

to any applicable

sanctions imposed by the U.S. against

Venezuela.

The Office of Natural Resources

Revenue (ONRR) has conducted audits

of ConocoPhillips' payment of royalties

on

federal lands and has issued multiple orders

to pay additional royalties

to the federal government.

ConocoPhillips

and the ONRR entered into a settlement

agreement on March 23, 2021, to resolve

the dispute.

All orders and

associated appeals have been withdrawn

with prejudice.

Beginning in 2017, governmental and

other entities in several states

in the U.S. have filed lawsuits against

oil and

gas companies, including ConocoPhillips,

seeking compensatory damages and equitable relief

to abate alleged

climate change impacts.

Additional lawsuits with similar allegations

are expected to be filed.

The amounts

claimed by plaintiffs are unspecified and

the legal and factual issues involved

in these cases are unprecedented.

ConocoPhillips believes these lawsuits are

factually and legally meritless and are

an inappropriate vehicle to

address the challenges associated with climate

change and will vigorously defend

against such lawsuits.

Several Louisiana parishes and the State

of Louisiana have filed

43

lawsuits under Louisiana's

State and Local

Coastal Resources Management

Act (SLCRMA) against oil and gas

companies, including ConocoPhillips, seeking

compensatory damages for contamination

and erosion of the Louisiana coastline allegedly

caused by historical oil

and gas operations.

ConocoPhillips entities are defendants

in

22

of the lawsuits and will vigorously defend

against

them.

Because Plaintiffs' SLCRMA theories are

unprecedented, there is uncertainty

about these claims (both as to

scope and damages) and we continue to

evaluate our exposure in these lawsuits

In October 2020, the Bureau of Safety and

Environmental Enforcement

(BSEE) ordered the prior owners of Outer

Continental Shelf (OCS) Lease P-0166,

including ConocoPhillips, to decommission

the lease facilities, including two

offshore platforms located

near Carpinteria, California.

This order was sent after the current

owner of OCS Lease

P-0166 relinquished the lease and

abandoned the lease platforms and facilities.

BSEE's order to

ConocoPhillips is

premised on its connection to Phillips Petroleum

Company,

a legacy company of ConocoPhillips,

which held a

historical

25

percent interest in this

lease and operated these facilities, but

sold its interest approximately

30

years

ago.

ConocoPhillips continues to evaluate

our exposure in these lawsuits.

On May 10, 2021, ConocoPhillips filed arbitration

under the rules of the Singapore International

Arbitration Centre

(SIAC) against Santos KOTN

Pty Ltd. and Santos Limited for

their failure to timely pay the $

200

million bonus due

upon FID of the Barossa development project

under the sale and purchase agreement.

Santos KOTN

Pty Ltd. and

Santos Limited have filed a response

and counterclaim, and the arbitration

is underway.

In July 2021, a federal securities class action

was filed against Concho, certain

of Concho's officers,

and

ConocoPhillips as Concho's

successor in the United States District Court

for the Southern District of Texas.

On

October 21, 2021, the court issued an order appointing

Utah Retirement Systems

and the Construction Laborers

Pension Trust

for Southern California as lead plaintiffs

(Lead Plaintiffs).

On January 7, 2022, the Lead Plaintiffs filed

their consolidated complaint alleging that

Concho made materially false and misleading

statements regarding

its

business and operations in violation of the federal

securities laws and seeking unspecified damages, attorneys'

fees, costs, equitable/injunctive

relief, and such

other relief that may be deemed appropriate.

We believe the

allegations in the action are without merit, and we

intend to vigorously defend

this litigation.

Long-Term Throughput

Agreements and Take

-or-Pay Agreements

We have certain throughput

agreements and take-or-pay

agreements in support of financing arrangements.

The

agreements typically provide for

natural gas or crude oil transportation

to be used in the ordinary course of

business.

The aggregate amounts of estimated

payments under these various agreements

are: 2022-$

7

million;

2023-$

7

million; 2024-$

7

million; 2025-$

7

million; 2026-$

7

million; and 2027 and after-$

43

million.

Total

payments under the agreements were

$

27

million in 2021, $

25

million in 2020 and $

25

million in 2019.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

110

Note 12-Derivative and Financial Instruments

We use futures, forwards,

swaps and options in various markets

to meet our customer needs, capture

market

opportunities, and manage foreign exchange

currency risk.

Commodity Derivative Instruments

Our commodity business primarily consists of natural

gas, crude oil, bitumen, LNG and NGLs.

Commodity derivative instruments

are held at fair value on our consolidated

balance sheet.

Where these balances

have the right of setoff,

they are presented on a net basis.

Related cash flows are recorded

as operating activities

on our consolidated statement

of cash flows.

On our consolidated income statement,

gains and losses are

recognized either on a gross

basis if directly related to our physical

business or a net basis if held for trading.

Gains

and losses related to contracts

that meet and are designated with the NPNS exception

are recognized upon

settlement.

We generally apply this

exception to eligible crude contracts

and certain gas contracts.

We do not

apply hedge accounting for our commodity

derivatives.

The following table presents the gross

fair values of our commodity derivatives,

excluding collateral,

and the line

items where they appear on our consolidated

balance sheet:

Millions of Dollars

2021

2020

Assets

Prepaid expenses and other current

assets

$

1,168

229

Other assets

75

26

Liabilities

Other accruals

1,160

202

Other liabilities and deferred credits

63

18

The gains (losses) from commodity derivatives

incurred, and the line items where they appear on our

consolidated

income statement were:

Millions of Dollars

2021

2020

2019

Sales and other operating revenues

$

(228)

19

141

Other income (loss)

25

4

4

Purchased commodities

75

11

(118)

On January 15, 2021, we assumed financial derivative instruments

consisting of oil and natural gas

swaps in

connection with the acquisition of Concho.

At the acquisition date, the financial derivative

instruments acquired

were recognized at fair

value as a net liability of $

456

million with settlement dates under the contracts

through

December 31, 2022.

During 2021, we recognized a loss

on settlement of the contracts for

$

305

million.

This loss

associated with the acquired financial instruments

is recorded within the "Sales and other operating

revenues" line

on our consolidated income statement.

In connection with the settlement, we issued

a cash payment of $

761

million during 2021.

Cash settlements related to

the derivative contracts

are presented within "Cash Flows From

Operating Activities" on our consolidated

statement of cash flows.

Notes to Consolidated Financial Statements

111

ConocoPhillips

2021 10-K

The table below summarizes our material

net exposures resulting from

outstanding commodity derivative

contracts:

Open Position

Long/(Short)

2021

2020

Commodity

Natural gas and power (billions

of cubic feet equivalent)

Fixed price

4

(20)

Basis

(22)

(10)

Foreign Currency Exchange

Derivatives

We have foreign

currency exchange rate

risk resulting from international

operations.

Our foreign currency

exchange derivative activity

primarily relates to managing our cash

-related foreign currency

exchange rate

exposures, such as firm commitments for

capital programs or local currency

tax payments, dividends and

cash

returns from net investments

in foreign affiliates, and

investments in equity securities.

Our foreign currency exchange

derivative instruments are

held at fair value on our consolidated

balance sheet.

Related cash flows are included

within operating activities on our consolidated

statement of cash flows.

We do

not elect hedge accounting on our foreign

currency exchange derivatives.

The following table presents the gross

fair values of our foreign currency

exchange derivatives,

excluding

collateral, and the line items where

they appear on our consolidated balance

sheet:

Millions of Dollars

2021

2020

Assets

Prepaid expenses and other current

assets

$

28

2

Liabilities

Other accruals

9

16

The (gains) losses from foreign

currency exchange derivatives

incurred and the line item where they appear

on our consolidated income statement

were:

Millions of Dollars

2021

2020

2019

Foreign currency transaction

(gains) losses

$

(5)

(40)

16

We had the following net notional

position of outstanding foreign currency

exchange derivatives:

In Millions

Notional Currency

2021

2020

Foreign Currency Exchange

Derivatives

Buy British pound, sell euro

GBP

155

Sell British pound, buy euro

GBP

5

Sell Canadian dollar,

buy U.S. dollar

CAD

370

Buy Canadian dollar,

sell U.S. dollar

CAD

77

Buy Australian dollar,

sell U.S. dollar

AUD

1,850

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

112

At December 31, 2021, we had outstanding foreign currency exchange forward contracts to buy $1.9 billion AUD at

$0.715 AUD against the U.S. dollar in anticipation of our future acquisition of an additional interest in APLNG. At

December 31, 2020, we had outstanding foreign currency exchange forward contracts to sell $0.45 billion CAD at

$0.748 CAD against the U.S. dollar

Financial Instruments

We invest in financial

instruments with maturities based on our cash

forecasts for the various

accounts and

currency pools we manage.

The types of financial instruments in which we currently

invest include:

●

Time deposits: Interest bearing deposits

placed with financial institutions for a predetermined

amount of

time.

●

Demand deposits:

Interest bearing deposits placed with financial

institutions.

Deposited funds can be

withdrawn without notice.

●

Commercial paper: Unsecured promissory

notes issued by a corporation, commercial

bank or government

agency purchased at a discount to

mature at par.

●

U.S. government or government

agency obligations: Securities issued by the U.S.

government or U.S.

government agencies.

●

Foreign government obligations:

Securities issued by foreign governments.

●

Corporate bonds:

Unsecured debt securities issued by corporations.

●

Asset-backed securities: Collateralized

debt securities.

The following investments

are carried on our consolidated

balance sheet at cost, plus accrued interest

and the

table reflects remaining maturities

at December 31, 2021 and 2020:

Millions of Dollars

Carrying Amount

Cash and Cash

Equivalents

Short-Term

Investments

Investments and Long-

Term Receivables

2021

2020

2021

2020

2021

2020

Cash

$

670

597

Demand Deposits

1,554

1,133

Time Deposits

1 to 90 days

2,363

1,225

217

2,859

91 to 180 days

4

448

Within one year

4

13

One year through five years

1

U.S. Government Obligations

1 to 90 days

431

23

$

5,018

2,978

225

3,320

1

Notes to Consolidated Financial Statements

113

ConocoPhillips

2021 10-K

The following investments

in debt securities classified as available for

sale are carried at fair value on

our

consolidated balance sheet at December 31, 2021 and

2020:

Millions of Dollars

Carrying Amount

Cash and Cash

Equivalents

Short-Term

Investments

Investments and Long-

Term Receivables

2021

2020

2021

2020

2021

2020

Major Security Type

Corporate Bonds

$

3

128

130

173

143

Commercial Paper

7

13

82

155

U.S. Government Obligations

4

2

13

U.S. Government Agency

Obligations

2

8

17

Foreign Government Obligations

7

2

2

Asset-backed Securities

2

63

41

$

10

13

221

289

248

216

Cash and Cash Equivalents and Short-Term

Investments have

remaining maturities within one year.

Investments and Long-Term

Receivables have remaining

maturities that vary from greater

than one year through

eight years.

The following table summarizes the

amortized cost basis and fair value

of investments in debt securities classified

as available for sale at December 31:

Millions of Dollars

Amortized Cost Basis

Fair Value

2021

2020

2021

2020

Major Security Type

Corporate Bonds

$

305

271

304

273

Commercial Paper

88

168

89

168

U.S. Government Obligations

2

17

2

17

U.S. Government Agency Obligations

10

17

10

17

Foreign Government Obligations

9

2

9

2

Asset-Backed Securities

65

41

65

41

$

479

516

479

518

As of December 31, 2021 and 2020, total unrealized

losses for debt securities classified as available

for sale with

net losses were negligible.

Additionally,

as of December 31, 2021 and 2020, investments in these

debt securities in

an unrealized loss position for which an

allowance for credit losses has not been

recorded were negligible.

For the years

ended December 31, 2021 and 2020, proceeds from sales and

redemptions of investments

in debt

securities classified as available for sale were

$

594

million and $

422

million, respectively.

Gross realized gains and

losses included in earnings from those sales and redemptions

were negligible.

The cost of securities sold and

redeemed is determined using the specific identification

method.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

114

Credit Risk

Financial instruments potentially exposed

to concentrations of credit

risk consist primarily of cash equivalents,

short-term investments, long-term

investments in debt securities,

OTC derivative contracts

and trade receivables.

Our cash equivalents and short-term

investments are placed

in high-quality commercial paper,

government money

market funds, U.S. government

and government agency obligations,

time deposits with major international banks

and financial institutions, high-quality corporate

bonds, foreign government obligations

and asset-backed

securities.

Our long-term investments in debt

securities are placed in high-quality corporate

bonds, asset-backed

securities, U.S. government and government

agency obligations, foreign

government obligations, and

time

deposits with major international banks

and financial institutions.

The credit risk from our OTC derivative

contracts, such as forwards,

swaps and options, derives from the

counterparty to the transaction.

Individual counterparty exposure is

managed within predetermined credit limits

and includes the use of cash-call margins when appropriate,

thereby reducing the risk of significant

nonperformance.

We also use futures, swaps

and option contracts that have

a negligible credit risk because these

trades are cleared primarily with an

exchange clearinghouse and subject to

mandatory margin requirements until

settled; however,

we are exposed to the credit risk

of those exchange brokers

for receivables arising from

daily

margin cash calls, as well as for cash

deposited to meet initial margin requirements.

Our trade receivables result primarily

from our petroleum operations

and reflect a broad national and

international customer base, which limits

our exposure to concentrations

of credit risk.

The majority of these

receivables have payment

terms of

30 days or less

, and we continually monitor this exposure

and the

creditworthiness of the counterparties.

We may require collateral

to limit the exposure to loss including,

letters of

credit, prepayments and surety

bonds, as well as master netting arrangements

to mitigate credit risk with

counterparties that both buy from and

sell to us, as these agreements permit the amounts

owed by us or owed to

others to be offset against

amounts due to us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure

exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable

threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for

lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below

investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of

credit as collateral, such as transactions administered through the New York Mercantile Exchange.

The aggregate fair value

of all derivative instruments with such credit

risk-related contingent

features that were in

a liability position on December 31, 2021 and December 31, 2020, was $

281

million and $

25

million, respectively.

For these instruments,

no

collateral was posted as

of December 31, 2021 or December 31, 2020.

If our credit

rating had been downgraded below investment

grade on December 31, 2021, we would

have been required to

post $

252

million of additional collateral, either with cash

or letters of credit.

Note 13-Fair Value

Measurement

We carry a portion of our assets and liabilities at

fair value that are measured at

the reporting date using an exit

price (i.e., the price that would be received to sell an

asset or paid to transfer

a liability) and disclosed according to

the quality of valuation inputs under the fair value

hierarchy.

The classification of an asset or liability is based on the lowest

level of input significant to its fair value.

Those that

are initially classified as Level 3 are subsequently

reported as Level 2 when the fair value derived

from unobservable

inputs is inconsequential to the overall

fair value, or if corroborated

market data becomes available.

Assets and

liabilities initially reported as Level 2 are subsequently

reported as Level 3 if corroborated

market data is no longer

available.

There were no material transfers

into or out of Level 3 during 2021 or 2020.

Notes to Consolidated Financial Statements

115

ConocoPhillips

2021 10-K

Recurring Fair Value

Measurement

Financial assets and liabilities reported at fair

value on a recurring basis primarily include our investment

in CVE

common shares, our investment

s

in debt securities classified as available for

sale, and commodity derivatives.

●

Level 1 derivative assets and

liabilities primarily represent exchange

-traded futures and options that

are

valued using unadjusted prices available

from the underlying exchange.

Level 1 also includes our investment

in common shares of CVE, which is valued using

quotes for shares on the NYSE, and

our investments in U.S.

government obligations classified

as available for sale debt securities,

which are valued using exchange

prices.

●

Level 2 derivative assets and

liabilities primarily represent OTC

swaps, options and forward

purchase and sale

contracts that are valued

using adjusted exchange prices,

prices provided by brokers

or pricing service

companies that are all corroborated

by market data.

Level 2 also includes our investments

in debt securities

classified as available for sale including

investments in corporate

bonds, commercial paper,

asset-backed

securities, U.S. government agency obligations

and foreign government obligations

that are valued using

pricing provided by brokers

or pricing service companies that are corroborated

with market data.

●

Level 3 derivative assets and

liabilities consist of OTC swaps,

options and forward purchase and

sale contracts

where a significant portion of fair value

is calculated from underlying market

data that is not readily available.

The derived value uses industry standard

methodologies that may consider the historical

relationships among

various commodities, modeled market

prices, time value, volatility factors

and other relevant economic

measures.

The use of these inputs results in management's

best estimate of fair value.

Level 3 activity was

not material for all periods presented.

The following table summarizes the

fair value hierarchy

for gross financial assets and liabilities (i.e., unadjusted

where the right of setoff exists

for commodity derivatives accounted

for at fair value on a recurring

basis):

Millions of Dollars

December 31, 2021

December 31, 2020

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

Assets

Investment in Cenovus Energy

$

1,117

1,117

1,256

1,256

Investments in debt securities

2

477

479

17

501

518

Commodity derivatives

562

619

62

1,243

142

101

12

255

Total

assets

$

1,681

1,096

62

2,839

1,415

602

12

2,029

Liabilities

Commodity derivatives

$

593

543

87

1,223

120

91

9

220

Total

liabilities

$

593

543

87

1,223

120

91

9

220

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

116

The following table summarizes those

commodity derivative balances subject to

the right of setoff as

presented on our consolidated

balance sheet.

We have elected to

offset the recognized fair

value amounts for

multiple derivative instruments

executed with the same counterparty

in our financial statements when a legal

right of setoff exists.

Millions of Dollars

Amounts Subject to Right of Setoff

Gross

Amounts Not

Gross

Net

Amounts

Subject to

Gross

Amounts

Amounts

Cash

Net

Recognized

Right of Setoff

Amounts

Offset

Presented

Collateral

Amounts

December 31, 2021

Assets

$

1,243

85

1,158

650

508

508

Liabilities

1,223

82

1,141

650

491

36

455

December 31, 2020

Assets

$

255

2

253

157

96

10

86

Liabilities

220

1

219

157

62

4

58

At December 31, 2021 and December 31, 2020, we did not present

any amounts gross on our consolidated

balance sheet where we had the right of setoff.

Non-Recurring Fair Value

Measurement

The following table summarizes the

fair value hierarchy

by major category and date of remeasurement

for assets

accounted for at fair value

on a non-recurring basis:

Millions of Dollars

Fair Value Measurements

Using

Fair Value

Level 1

Inputs

Level 2

Inputs

Level 3

Inputs

Before-Tax

Loss

Year ended

December 31, 2021

Net PP&E (held for use)

December 31, 2021

$

472

472

80

Equity Method Investments

December 31, 2021

5,574

5,574

688

Year ended December 31,

2020

Net PP&E (held for use)

March 31, 2020

$

65

65

522

December 31, 2020

268

268

287

Net PP&E (held for use)

During 2021 and 2020, the estimated fair value

of certain noncore assets included

in our Lower 48 segment

declined to amounts below the carrying values.

The carrying values were written down

to fair value.

The fair

values were estimated based

on internal discounted cash

flow models using the following estimated assumptions:

estimated future production,

an outlook of future prices from a combination

of exchanges (short-term) coupled

with pricing service companies and our internal outlook

(long-term), future operating costs

and capital

expenditures, and a discount rate

believed to be consistent with

those used by principal market participants.

The

range and arithmetic average

of significant unobservable inputs used in the Level

3 fair value measurements for

significant assets were as follows:

Notes to Consolidated Financial Statements

117

ConocoPhillips

2021 10-K

Fair Value

(Millions of

Dollars)

Valuation

Technique

Unobservable Inputs

Range

(Arithmetic Average)

December 31, 2021

Lower 48 Gulf Coast and

Rockies noncore field

$

472

Discounted

cash flow

Commodity production

(MBOED)

0.2

17

(

5.4

)

Commodity price outlook*

($/BOE)

$

41.45

• $

93.68

($

64.39

)

Discount rate**

7.3

%

9.7

% (

8.7

%)

*Commodity price outlook based on a combination of external

pricing service companies' and our internal

outlook for years 2024-2050; future prices escalated

at

2.0

% annually after year 2050.

**Determined as the weighted average cost

of capital of a group of peer companies,

adjusted for risks where appropriate.

Fair Value

(Millions of

Dollars)

Valuation

Technique

Unobservable Inputs

Range

(Arithmetic Average)

March 31, 2020

Wind River Basin

$

65

Discounted

cash flow

Natural gas production

(MMCFD)

8.4

55.2

(

22.9

)

Natural gas price outlook*

($/MMBTU)

$

2.67

• $

9.17

($

5.68

)

Discount rate**

7.9

% -

9.1

% (

8.3

%)

*Henry Hub natural gas price outlook based on a combination

of external pricing service companies' outlooks

for years 2022-2034; future prices escalated

at

2.2

%

annually after year 2034.

**Determined as the weighted average cost

of capital of a group of peer companies,

adjusted for risks where appropriate.

Fair Value

(Millions of

Dollars)

Valuation

Technique

Unobservable Inputs

Range

(Arithmetic Average)

December 31, 2020

Central Basin Platform

$

244

Discounted

cash flow

Commodity production

(MBOED)

0.5

12.7

(

3.4

)

Commodity price outlook*

($/BOE)

$

37.35

• $

115.29

($

73.80

)

Discount rate**

6.8

% -

7.7

% (

7.4

%)

*Commodity price outlook based on a combination of external

pricing service companies' and our internal

outlook for years 2023-2050; future prices escalated

at

2.0

% annually after year 2050.

**Determined as the weighted average cost

of capital of a group of peer companies,

adjusted for risks where appropriate.

Equity Method Investments

During the fourth quarter of 2021, Origin Energy Limited

agreed to the sale of

10

percent of their interest in

APLNG

for $

1.645

billion, before customary

adjustments.

ConocoPhillips announced in December 2021 that we were

exercising our preemption

right under the APLNG Shareholders Agreement

to purchase an additional 10 percent

shareholding interest in APLNG, subject

to government approvals.

The sales price associated with this preemption

right was determined to reflect

a relevant observable market

participant view of APLNG's

fair value which was

below the carrying value of our existing

investment in APLNG.

As such, our investment in APLNG was

written

down to its fair value of $

5,574

million, resulting in a before-tax

charge of $

688

million.

See Note 4

and

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

118

Reported Fair Values

of Financial Instruments

We used the following methods

and assumptions to estimate the fair value

of financial instruments:

●

Cash and cash equivalents and short-term investments:

The carrying amount reported on the balance

sheet approximates fair

value.

For those investments classified as

available for sale debt securities,

the

carrying amount reported on the balance sheet

is fair value.

●

Accounts and notes receivable (including

long-term and related parties): The carrying

amount reported on

the balance sheet approximates

fair value.

The valuation technique and methods

used to estimate the

fair value of the current portion of fixed

-rate related party

loans is consistent with Loans and advances-

related parties.

●

Investment in Cenovus Energy:

See Note 5

for a discussion of the carrying value and fair

value of our

investment in CVE common shares.

●

Investments in debt securities classified

as available for sale: The fair value

of investments in debt

securities categorized as Level

1 in the fair value hierarchy

is measured using exchange prices.

The fair

value of investments in debt

securities categorized as Level 2 in

the fair value hierarchy

is measured using

pricing provided by brokers

or pricing service companies that are corroborate

d

with market data.

Note

12

●

Loans and advances-related parties: The carrying

amount of floating-rate loans

approximates fair value.

The fair value of fixed-rate

loan activity is measured using market

observable data and is categorized

as

Level 2 in the fair value hierarchy.

See Note

4

●

Accounts payable (including related

parties) and floating-rate debt:

The carrying amount of accounts

payable and floating-rate

debt reported on the balance sheet approximates

fair value.

●

Fixed-rate debt: The estimated

fair value of fixed-rate

debt is measured using prices available from

a

pricing service that is corroborated

by market data; therefore,

these liabilities are categorized

as Level 2 in

the fair value hierarchy.

●

Commercial paper: The carrying amount of our commercial

paper instruments approximates

fair value

and is reported on the balance sheet as short-term

debt

The following table summarizes the

net fair value of financial instruments

(i.e., adjusted where the right of setoff

exists for commodity derivatives):

Millions of Dollars

Carrying Amount

Fair Value

2021

2020

2021

2020

Financial assets

Investment in CVE common shares

$

1,117

1,256

1,117

1,256

Commodity derivatives

593

88

593

88

Investments in debt securities

479

518

479

518

Loans and advances-related parties

114

220

114

220

Financial liabilities

Total

debt, excluding finance leases

18,673

14,478

22,451

19,106

Commodity derivatives

537

59

537

59

Commodity Derivatives

At December 31, 2021, commodity derivative

assets and liabilities are presented net with

no

obligation to return

cash collateral and $

36

million of rights to reclaim cash collateral,

respectively.

At December 31, 2020, commodity

derivative assets and liabilities are presented

net with $

10

million in obligations to return

cash collateral and

$

4

million of rights to reclaim cash collateral,

respectively.

Notes to Consolidated Financial Statements

119

ConocoPhillips

2021 10-K

Note 14-Equity

Common Stock

The changes in our shares of common stock,

as categorized in the equity section

of the balance sheet, were:

Shares

2021

2020

2019

Issued

Beginning of year

1,798,844,267

1,795,652,203

1,791,637,434

Acquisition of Concho

285,928,872

Distributed under benefit plans

6,789,608

3,192,064

4,014,769

End of year

2,091,562,747

1,798,844,267

1,795,652,203

Held in Treasury

Beginning of year

730,802,089

710,783,814

653,288,213

Repurchase of common stock

58,517,786

20,018,275

57,495,601

End of year

789,319,875

730,802,089

710,783,814

Preferred Stock

We have authorized

500

million shares of preferred

stock, par value $

0.01

per share,

none

of which was issued or

outstanding at December 31, 2021 or 2020.

Noncontrolling Interests

In the second quarter of 2020, we completed the divestiture

of our subsidiaries that held our Australia

-West assets

and operations.

These assets included the Darwin LNG and Bayu-Darwin Pipeline operating

joint ventures in which

there was a noncontrolling interest.

As a result, as of December 31, 2021 and 2020, we had no

noncontrolling

interests.

Repurchase of Common Stock

In late 2016, we initiated our current

share repurchase program,

which has a current total program

authorization

of $

25

billion of our common stock.

In May 2021, we began a paced monetization

of our CVE common shares, the

proceeds of which have been applied to

share repurchases.

Share repurchases since inception of our current

program totaled

247

million shares at a cost of $

14

billion through the end of December 2021.

Note 15-Non-Mineral Leases

The company primarily leases office buildings

and drilling equipment, as well as ocean transport

vessels, tugboats,

corporate aircraft,

and other facilities and equipment.

Certain leases include escalation clauses for

adjusting rental

payments to reflect changes in

price indices and other leases include payment provisions

that vary based on the

nature of usage of the leased asset.

Additionally, the company

has executed certain leases that

provide it with the

option to extend or renew the term of

the lease, terminate the lease prior to the end

of the lease term, or

purchase the leased asset as of the end of the lease term.

In other cases, the company has executed

lease

agreements that require it to

guarantee the residual value

of certain leased office buildings.

For additional

information about guarantees,

see Note 10

There are no significant restrictions

imposed on us by the lease

agreements with regard to

dividends, asset dispositions or borrowing ability.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

120

Certain arrangements may

contain both lease and non-lease components

and we determine if an arrangement

is

or contains a lease at contract

inception.

We adopted the provisions

of FASB ASU No. 2016-02, "Leases" (ASC

Topic 842) and

its amendments, beginning January 1, 2019.

This ASU superseded the requirements in

FASB ASC

Topic 840 "Leases"

(ASC Topic

840).

Only the lease components of these contractual

arrangements are subject to

the provisions of ASC Topic

842, and any non-lease components

are subject to other applicable accounting

guidance; however,

we have elected to adopt

the optional practical expedient not to

separate lease components

apart from non-lease components for

accounting purposes.

This policy election has been adopted for each of the

company's leased asset

classes existing as of the effective date

and subject to the transition provisions

of ASC

Topic 842 and will be applied

to all new or modified leases executed on

or after January 1, 2019.

For contractual

arrangements executed

in subsequent periods involving

a new leased asset class, the company will determine

at

contract inception whether it will apply

the optional practical expedient to

the new leased asset class.

Leases are evaluated for classification

as operating or finance leases at the commencement

date of the lease and

right-of-use assets and corresponding

liabilities are recognized on our

consolidated balance sheet based on the

present value of future lease payments

relating to the use of the underlying asset during the lease term.

Future

lease payments include variable lease payments

that depend upon an index or rate

using the index or rate at the

commencement date and probable

amounts owed under residual value

guarantees.

The amount of future lease

payments may be increased to

include additional payments related

to lease extension, termination,

and/or

purchase options when the company has

determined, at or subsequent to lease commencement,

generally due to

limited asset availability or operating

commitments, it is reasonably certain

of exercising such options.

We use our

incremental borrowing rate

as the discount rate in

determining the present value of future

lease payments, unless

the interest rate implicit in

the lease arrangement is readily

determinable.

Lease payments that vary

subsequent

to the commencement date based on future

usage levels, the nature of leased asset activities,

or certain other

contingencies are not included in the measurement

of lease right-of-use assets and corresponding

liabilities.

We

have elected not to record

assets and liabilities on our consolidated balance

sheet for lease arrangements with

terms of 12 months or less.

We often enter into

leasing arrangements acting in the capacity as

operator for and/or

on behalf of certain oil and

gas joint ventures of undivided interests.

If the lease arrangement can be legally enforced

only against us as

operator and there is no separate

arrangement to sublease the underlying

leased asset to our coventurers,

we

recognize at lease commencement

a right-of-use asset and corresponding

lease liability on our consolidated

balance sheet on a gross basis.

While we record lease costs on a

gross basis in our consolidated income statement

and statement of cash flows,

such costs are offset by the reimbursement

we receive from our coventurers

for their

share of the lease cost as the underlying leased asset

is utilized in joint venture activities.

As a result, lease cost is

presented in our consolidated

income statement and statement

of cash flows on a proportional basis.

If we are a

nonoperating coventurer,

we recognize a right-of-use asset and

corresponding lease liability only if we were a

specified contractual party to the lease arrangement

and the arrangement could be legally

enforced against us.

In

this circumstance, we would recogni

ze both the right-of-use asset

and corresponding lease liability on our

consolidated balance sheet on a proportional

basis consistent with our undivided interest

ownership in the related

joint venture.

The company has historically recorded

certain finance leases executed

by investee companies

accounted for under

the proportionate consolidation

method of accounting on its consolidated

balance sheet on a proportional basis

consistent with its ownership

interest in the investee

company.

In addition, the company has historically

recorded

finance lease assets and liabilities associated with certain

oil and gas joint ventures on a proportional

basis

pursuant to accounting guidance applicable

prior to January 1, 2019.

In accordance with the transition

provisions

of ASC Topic 842, and

since we have elected to adopt

the package of optional transition-related

practical

expedients, the historical accounting

treatment for these leases has been carried

forward and is subject to

reconsideration upon the modification

or other required reassessment

of the arrangements prior to lease term

expiration.

Notes to Consolidated Financial Statements

121

ConocoPhillips

2021 10-K

The following table summarizes the

right-of-use assets and lease liabilities for both

the operating and finance

leases on our consolidated balance sheet as of December 31:

Millions of Dollars

2021

2020

Operating

Leases

Finance

Leases

Operating

Leases

Finance

Leases

Right-of-Use Assets

Properties, plants and equipment

Gross

$

1,812

1,375

Accumulated DD&A

(857)

(721)

Net PP&E

955

654

Prepaid expenses and other current

assets

$

16

2

Other assets

649

783

Lease Liabilities

Short-term debt

**

$

280

168

Other accruals

188

226

Long-term debt

---

981

723

Other liabilities and deferred credits

479

559

Total

lease liabilities

$

667

1,261

785

891

Includes proportionately consolidated finance lease assets of $

208

million at December 31, 2021 and $

258

million at December 31, 2020.

**

Includes proportionately consolidated finance lease liabilities of $

154

million at December 31, 2021 and $

97

million at December 31, 2020.

---

Includes proportionately consolidated finance lease liabilities of $

462

million at December 31, 2021 and $

522

million at December 31,

The following table summarizes our

lease costs:

Millions of Dollars

2021

2020

2019

Lease Cost

Operating lease cost

$

278

321

341

Finance lease cost

Amortization of right-of-use assets

148

163

99

Interest on lease liabilities

27

34

37

Short-term lease cost

**

21

42

77

Total

lease cost

---

$

474

560

554

The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas

coventurers.

**

Short-term leases are not recorded on our consolidated balance sheet.

*** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

122

The following table summarizes the

lease terms and discount rates

as of December 31:

2021

2020

Lease Term

and Discount Rate

Weighted-average

term (years)

Operating leases

5.97

6.11

Finance leases

7.49

7.12

Weighted-average

discount rate (percent)

Operating leases

2.66

2.78

Finance leases

3.24

4.27

The following table summarizes other

lease information:

Millions of Dollars

2021

2020

2019

Other Information

Cash paid for amounts included in the measurement

of lease liabilities

Operating cash flows from operating

leases

$

204

232

203

Operating cash flows from finance

leases

6

11

27

Financing cash flows from finance leases

73

255

81

Right-of-use assets obtained

in exchange for operating

lease liabilities

$

174

250

499

Right-of-use assets obtained

in exchange for finance lease liabilities

447

426

26

*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.

In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its

intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.

The following table summarizes future

lease payments for operating

and finance leases at December 31, 2021:

Millions of Dollars

Operating

Leases

Finance

Leases

Maturity of Lease Liabilities

2022

$

195

341

2023

143

199

2024

114

166

2025

68

143

2026

50

139

Remaining years

159

462

Total

729

1,450

Less: portion representing imputed

interest

(62)

(189)

Total

lease liabilities

$

667

1,261

*Future lease payments for operating and finance leases commencing on or after January 1, 2019, also include payments related to non-lease

components in accordance with our election to adopt the optional practical expedient not to separate lease components apart from non-lease

components for accounting purposes.

In addition, future payments related to operating and finance leases proportionately consolidated by the

company have been included in the table on a proportionate basis consistent with our respective ownership interest in the underlying investee

company or oil and gas venture.

Notes to Consolidated Financial Statements

123

ConocoPhillips

2021 10-K

Note 16-Employee Benefit Plans

Pension and Postretirement

Plans

An analysis of the projected benefit obligations

for our pension plans and accumulated benefit obligations

for

our postretirement health and life

insurance plans follows:

Millions of Dollars

Pension Benefits

Other Benefits

2021

2020

2021

2020

U.S.

Int'l.

U.S.

Int'l.

Change in Benefit Obligation

Benefit obligation at January 1

$

2,548

4,403

2,319

3,880

170

216

Service cost

73

61

85

54

2

2

Interest cost

53

79

66

85

4

6

Plan participant contributions

1

16

18

Plan amendments

2

(30)

Actuarial (gain) loss

(117)

(176)

319

398

(16)

7

Benefits paid

(654)

(162)

(241)

(151)

(40)

(49)

Curtailment

12

2

1

Recognition of termination benefits

9

3

Foreign currency exchange

rate change

(81)

129

Benefit obligation at December 31

$

1,924

4,124

2,548

4,403

137

170

*Accumulated benefit obligation portion of above at

December 31:

$

1,793

3,658

2,359

4,095

Change in Fair Value

of Plan Assets

Fair value of plan assets at January

1

$

1,770

4,793

1,591

4,306

Actual return on plan assets

97

147

321

416

Company contributions

451

119

99

60

24

31

Plan participant contributions

1

1

16

18

Benefits paid

(654)

(162)

(241)

(151)

(40)

(49)

Foreign currency exchange

rate change

(86)

161

Fair value of plan assets at December 31

$

1,664

4,812

1,770

4,793

Funded Status

$

(260)

688

(778)

390

(137)

(170)

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

124

Millions of Dollars

Pension Benefits

Other Benefits

2021

2020

2021

2020

U.S.

Int'l.

U.S.

Int'l.

Amounts Recognized in the

Consolidated Balance Sheet at

December 31

Noncurrent assets

$

1

991

746

Current liabilities

(29)

(15)

(56)

(11)

(34)

(39)

Noncurrent liabilities

(232)

(288)

(722)

(345)

(103)

(131)

Total

recognized

$

(260)

688

(778)

390

(137)

(170)

Weighted-Average

Assumptions Used to

Determine Benefit Obligations at

December 31

Discount rate

2.80

%

2.15

2.30

1.80

2.65

2.15

Rate of compensation increase

4.00

3.40

4.00

3.10

Interest crediting rate

for applicable benefits

2.50

2.10

Weighted-Average

Assumptions Used to

Determine Net Periodic Benefit Cost

for

Years Ended

December 31

Discount rate

2.60

%

1.80

3.05

2.35

2.35

3.10

Expected return on plan assets

5.20

2.50

5.80

3.60

Rate of compensation increase

4.00

3.40

4.00

3.35

Interest crediting rate

for applicable benefits

2.10

4.10

For both U.S. and international pension

plans, the overall expected long-term

rate of return is developed

from the

expected future return of each asset

class, weighted by the expected allocation

of pension assets to that asset

class.

We rely on a variety of independent

market forecasts

in developing the expected rate

of return for each

class of assets.

During 2021, the actuarial gains related

to the benefit obligations for

U.S. and international plans were primarily

related to an increase in the discount

rates.

During 2020 and 2019, the actuarial losses related to

the benefit

obligations for U.S. and international

plans were primarily related to a decrease

in the discount rates.

Notes to Consolidated Financial Statements

125

ConocoPhillips

2021 10-K

The following tables summarize information

related to the Company's

pension plans with projected and

accumulated benefit obligations

in excess of the fair value of the plans'

assets:

Millions of Dollars

Pension Benefits

2021

2020

U.S.

Int'l.

U.S.

Int'l.

Pension Plans with Projected Benefit Obligation

in

Excess of Plan Assets

Projected benefit obligation

$

261

362

2,548

391

Fair value of plan assets

58

1,770

35

Pension Plans with Accumulated Benefit

Obligation in

Excess of Plan Assets

Accumulated benefit obligation

$

234

271

2,359

338

Fair value of plan assets

9

1,770

35

Included in accumulated other comprehensive

income (loss) at December 31 were the following

before-tax

amounts that had not been recognized

in net periodic benefit cost:

Millions of Dollars

Pension Benefits

Other Benefits

2021

2020

2021

2020

U.S.

Int'l.

U.S.

Int'l.

Unrecognized net actuarial loss

(gain)

$

188

86

467

326

(1)

14

Unrecognized prior service cost

(credit)

1

(145)

(182)

Millions of Dollars

Pension Benefits

Other Benefits

2021

2020

2021

2020

U.S.

Int'l.

U.S.

Int'l.

Sources of Change in Other

Comprehensive Income (Loss)

Net gain (loss) arising during the period

$

134

207

(83)

(120)

16

(7)

Amortization of actuarial loss included

in income (loss)*

145

33

95

21

1

Net change during the period

$

279

240

12

(99)

16

(6)

Prior service credit (cost) arising during the

period

$

(1)

30

Amortization of prior service (credit)

included in income (loss)

(1)

(1)

(37)

(31)

Net change during the period

$

(1)

(2)

(37)

(1)

*Includes settlement (gains) losses recognized in 2021 and 2020.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

126

The components of net periodic benefit cost of all defined

benefit plans are presented in the following

table:

Millions of Dollars

Pension Benefits

Other Benefits

2021

2020

2019

2021

2020

2019

U.S.

Int'l.

U.S.

Int'l.

U.S.

Int'l.

Components of Net

Periodic Benefit Cost

Service cost

$

73

61

85

54

79

69

2

2

1

Interest cost

53

79

66

85

79

97

4

6

8

Expected return on plan

assets

(80)

(120)

(85)

(145)

(74)

(138)

Amortization of prior

service credit

(1)

(1)

(2)

(37)

(31)

(33)

Recognized net actuarial

loss (gain)

43

33

51

22

54

32

1

(2)

Settlements loss (gain)

102

44

(1)

62

Curtailment loss

12

Net periodic benefit cost

$

203

52

161

14

200

58

(31)

(22)

(26)

The components of net periodic benefit cost,

other than the service cost component, are included

in the "Other

expenses" line item on our consolidated

income statement.

We recognized pension

settlement losses of $

102

million in 2021, $

43

million in 2020, and $

62

million in 2019 as

lump-sum benefit payments from certain

U.S. and international pension

plans exceeded the sum of service and

interest costs for

those plans and led to recognition of settlement

losses.

In determining net pension and other postretirement

benefit costs, we amortize

prior service costs on a straight-

line basis over the average

remaining service period of employees expected to

receive benefits under the plan.

For

net actuarial gains and losses, we amortize

10

percent of the unamortized balance each year.

We have multiple non-pension

postretirement benefit plans

for health and life insurance.

The health care plans

are contributory and subject to various

cost sharing features, with participant

and company contributions adjusted

annually; the life insurance plans

are noncontributory.

The measurement of the U.S. pre-65 retiree

medical

accumulated postretirement

benefit obligation assumes a health care

cost trend rate of

6.5

percent in 2022 that

declines to

5

percent by 2028.

The measurement of the U.S. post-65

retiree medical accumulated

postretirement

benefit obligation assumes a health care

cost trend rate of

4.25

percent in 2022 that increases to

5

percent by

Notes to Consolidated Financial Statements

127

ConocoPhillips

2021 10-K

Plan Assets

We follow a policy of broadly

diversifying pension plan assets across asset

classes and individual holdings.

As a

result, our plan assets have no significant

concentrations of credit risk.

Asset classes that are considered

appropriate include U.S. equities,

non-U.S. equities, U.S. fixed

income, non-U.S. fixed income, real

estate and

private equity investments.

Plan fiduciaries may consider and add other asset classes to

the investment program

from time to time.

The target allocations for

plan assets are

22

percent equity securities,

74

percent debt

securities,

3

percent real estate

and

1

percent other.

Generally,

the plan investments are publicly

traded,

therefore minimizing liquidity risk

in the portfolio.

The following is a description of the valuation

methodologies used for the pension plan assets.

There have been

no changes in the methodologies used at December 31, 2021 and

●

Fair values of equity securities and government

debt securities categorized in Level

1 are primarily based

on quoted market prices in active

markets for identical assets

and liabilities.

●

Fair values of corporate

debt securities, agency and mortgage-backed

securities and government debt

securities categorized in Level

2 are estimated using recently

executed transactions

and quoted market

prices for similar assets and liabilities in active markets

and for identical assets and liabilities in markets

that are not active.

If there have been no market transactions

in a particular fixed income security,

its fair

value is calculated by pricing models that

benchmark the security against other securities with actual

market prices.

When observable quoted market

prices are not available, fair

value is based on pricing

models that use something other than actual market

prices (e.g., observable inputs such as benchmark

yields, reported trades and issuer spreads

for similar securities), and these securities are categorized

in

Level 3 of the fair value hierarchy.

●

Fair values of investments

in common/collective trusts are

determined by the issuer of each fund based

on the fair value of the underlying assets.

●

Fair values of mutual funds are based

on quoted market prices, which represent

the net asset value of

shares held.

●

Time deposits are valued at cost,

which approximates fair value.

●

Cash is valued at cost, which approximates

fair value.

Fair values of international

cash equivalents

categorized in Level 2 are

valued using observable yield curves, discounting

and interest rates.

U.S. cash

balances held in the form of short-term fund units

that are redeemable at the measurement

date are

categorized as Level 2.

●

Fair values of exchange

-traded derivatives classified

in Level 1 are based on quoted market

prices.

For

other derivatives classified in Level 2, the values

are generally calculated from

pricing models with market

input parameters from third

-party sources.

●

Fair values of insurance contracts

are valued at the present value

of the future benefit payments owed

by

the insurance company to

the plans' participants.

●

Fair values of real estate

investments are valued

using real estate valuation

techniques and other

methods that include reference

to third-party sources and sales comparables

where available.

●

A portion of U.S. pension plan assets is held as a participating interest

in an insurance annuity contract,

which is calculated as the market

value of investments held under

this contract, less the accumulated

benefit obligation covered by

the contract.

The participating interest is classified as

Level 3 in the fair

value hierarchy as

the fair value is determined via a combination

of quoted market prices, recently

executed transactions,

and an actuarial present value computation

for contract obligations.

At

December 31, 2021, the participating interest

in the annuity contract was valued

at $

83

million and

consisted of $

206

million in debt securities, less $

123

million for the accumulated benefit obligation

covered by the contract.

At December 31, 2020, the participating interest

in the annuity contract was

valued at $

94

million and consisted of $

233

million in debt securities, less $

139

million for the

accumulated benefit obligation

covered by the contract.

The participating interest is not available

for

meeting general pension benefit obligations

in the near term.

No future company contributions

are

required and no new benefits are being accrued under

this insurance annuity contract.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

128

The fair values of our pension plan assets at

December 31, by asset class were as follows:

Millions of Dollars

U.S.

International

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

2021

Equity securities

U.S.

$

3

5

8

International

42

42

Mutual funds

17

17

236

403

639

Debt securities

Corporate

1

1

Mutual funds

511

511

Cash and cash equivalents

68

68

Real estate

157

157

Total in fair

value hierarchy

$

62

1

5

68

815

403

157

1,375

Investments measured at net asset value*

Equity securities

Common/collective trusts

$

394

417

Debt securities

Common/collective trusts

1,073

3,015

Cash and cash equivalents

9

Real estate

36

1

Total**

$

62

1

5

1,580

815

403

157

4,808

*In accordance with FASB ASC Topic 715, "Compensation-Retirement Benefits,"

certain investments that are to be measured at fair value

using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.

The fair value

amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in

Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a net asset of $

83

million and net receivables related to security

transactions of $

5

million.

Notes to Consolidated Financial Statements

129

ConocoPhillips

2021 10-K

The fair values of our pension plan assets at

December 31, by asset class were as follows:

Millions of Dollars

U.S.

International

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

2020

Equity securities

U.S.

$

3

5

8

International

99

99

Mutual funds

72

72

235

384

619

Debt securities

Corporate

1

1

Mutual funds

455

455

Cash and cash equivalents

74

74

Derivatives

6

6

Real estate

142

142

Total in fair

value hierarchy

$

171

4

5

180

770

384

142

1,296

Investments measured at net asset value*

Equity securities

Common/collective trusts

$

678

372

Debt securities

Common/collective trusts

730

3,007

Cash and cash equivalents

8

Real estate

79

112

Total**

$

171

4

5

1,675

770

384

142

4,787

*In accordance with FASB ASC Topic 715, "Compensation-Retirement Benefits,"

certain investments that are to be measured at fair value

using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.

The fair value

amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in

Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a net asset of $

94

million and net receivables related to security

transactions of $

7

million.

Level 3 activity was not material for all periods.

Our funding policy for U.S. plans is to contribute

at least the minimum required by the Employee

Retirement

Income Security Act of 1974 and the Internal Revenue

Code of 1986, as amended.

Contributions to foreign plans

are dependent upon local laws and tax

regulations.

In 2022, we expect to contribute

approximately $

115

million

to our domestic qualified and nonqualified pension

and postretirement benefit plans

and $

80

million to our

international qualified and nonqualified pension and

postretirement benefit plans.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

130

The following benefit payments,

which are exclusive of amounts

to be paid from the insurance annuity contract

and which reflect expected future

service, as appropriate, are expected

to be paid:

Millions of Dollars

Pension

Other

Benefits

Benefits

U.S.

Int'l.

2022

$

369

152

21

2023

185

152

18

2024

176

158

15

2025

154

162

14

2026

144

164

12

2027-2031

557

893

44

The following table summarizes our

severance accrual activity:

Millions of Dollars

2021

2020

2019

Balance at January 1

$

24

23

48

Accruals

170

14

(1)

Benefit payments

(116)

(13)

(24)

Balance at December 31

$

78

24

23

Accruals include severance costs

associated with our company-wide restructuring

program.

Of the remaining

balance at December 31, 2021, $

43

million is classified as short-term.

Defined Contribution Plans

Most U.S. employees are eligible

to participate in the ConocoPhillips Savings

Plan (CPSP).

Employees can deposit

up to

75

percent of their eligible pay,

subject to statutory limits, in the CPSP to a choice of

17

investment options.

Employees who participate in the CPSP and contribute

1

percent of their eligible pay receive

a

6

percent company

cash match with a potential company

discretionary cash contribution of up

to

6

percent.

Effective January 1, 2019,

new employees, rehires, and employees

that elected to opt out of Title II of the ConocoPhillips

Retirement Plan are

eligible to receive a Company Retirement

Contribution (CRC) of

6

percent of eligible pay into

their CPSP.

After

three years

of service with the company,

the employee is

100

percent vested in any

CRC.

Company contributions

charged to expense for the CPSP and

predecessor plans were $

93

million in 2021, $

62

million in 2020, and $

82

million in 2019.

We have several

defined contribution plans for our

international employees, each with its own

terms and eligibility

depending on location.

Total

compensation expense recognized

for these international plans was

approximately

$

26

million in 2021, $

25

million in 2020, and $

30

million in 2019.

Share-Based Compensation Plans

The 2014 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips (the Plan) was approved

by

shareholders in May 2014, replacing

similar prior plans and providing that no new awards

shall be granted under

the prior plans.

Over its

10

-year life, the Plan allows the issuance

of up to

79

million shares of our common stock

for compensation to our employees

and directors; however,

as of the effective date of the

Plan, (i) any shares of

common stock available for

future awards under the prior plans

and (ii) any shares of common stock

represented

by awards granted

under the Plan or the prior plans that are forfeited,

expire or are cancelled without

delivery of

shares of common stock or which result

in the forfeiture of shares

of common stock back to the company

shall be

available for awards

under the Plan.

Of the

79

million shares available for

issuance under the Plan, no more than

40

million shares of common stock are

available for incentive stock

options.

The Human Resources and

Compensation Committee of our Board

of Directors is authorized to

determine the types, terms, conditions and

limitations of awards granted.

Awards may be granted

in the form of, but not

limited to, stock options, restricted

Notes to Consolidated Financial Statements

131

ConocoPhillips

2021 10-K

stock units and performance share units

to employees and non-employee directors

who contribute to the

company's continued

success and profitability.

Total

share-based compensation expense is

measured using the grant date

fair value for our equity-classified

awards and the settlement date

fair value for our liability-classified awards.

We recognize share

-based

compensation expense over the shorter

of the service period (i.e., the stated period of time required

to earn the

award); or the period beginning at the start

of the service period and ending when an employee first becomes

eligible for retirement, but

not less than six months, as this is the minimum period of time required

for an award to

not be subject to forfeiture.

Our share-based compensation programs

generally provide accelerated

vesting (i.e., a

waiver of the remaining period of service required

to earn an award) for awards

held by employees at the time of

their retirement.

Some of our share-based awards

vest ratably (i.e., portions

of the award vest at different

times)

while some of our awards cliff vest

(i.e., all of the award vests at

the same time).

We recognize

expense on a

straight-line basis over the service period for

the entire award, whether the

award was granted

with ratable or cliff

vesting.

Compensation Expense

-Total

share-based compensation expense recognized

in net income (loss) and the

associated tax benefit were:

Millions of Dollars

2021

2020

2019

Compensation cost

$

304

159

274

Tax benefit

76

40

71

Stock Options

-Stock options granted under

the provisions of the Plan and prior plans permit purchase of our

common stock at exercise

prices equivalent to the average

fair market value of ConocoPhillips

common stock on

the date the options were granted.

The options have terms of 10 years

and generally vest ratably,

with one-third

of the options awarded vesting and

becoming exercisable on

each anniversary date following the date

of grant.

Options awarded to certain employees

already eligible for retirement

vest within six months of the grant

date, but

those options do not become exercisable

until the end of the normal vesting period.

Beginning in 2018, stock

option grants were discontinued

and replaced with three-year,

time-vested restricted

stock units which generally

will be cash-settled for 2018 and 2019 awards

and stock-settled beginning

with 2020 awards.

The following summarizes our stock

option activity for the year ended December 31, 2021:

Millions of Dollars

Weighted-Average

Aggregate

Options

Exercise Price

Intrinsic Value

Outstanding at December 31, 2020

16,922,525

$

55.12

$

22

Exercised

(3,846,361)

51.40

68

Expired or cancelled

(1,102,381)

53.47

Outstanding at December 31, 2021

11,973,783

$

56.46

$

188

Vested at December

31, 2021

11,973,783

$

56.46

$

188

Exercisable at December 31, 2021

11,973,783

$

56.46

$

188

The weighted-average remaining

contractual term of outstanding

options, vested options and exercisable

options

at December 31, 2021, were all

3.06

years.

The aggregate intrinsic value

of options exercised was

$

23

million in

2020 and $

39

million in 2019.

During 2021, we received $

198

million in cash and realized a tax

benefit of $

15

million from the exercise of

options.

At December 31, 2021, all outstanding stock

options were fully vested and there

was no remaining

compensation cost to be recorded.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

132

Stock Unit Program-

Generally,

restricted stock units are granted

annually under the provisions of the Plan and

vest in an aggregate installment

on the third anniversary of the grant

date.

In addition, restricted stock

units

granted under the Plan for a variable

long-term incentive program

vest ratably in three

equal annual installments

beginning on the first anniversary of the grant

date.

Restricted stock units are also

granted ad hoc to attract

or

retain key personnel,

and the terms and conditions under which these restricted

stock units vest vary by award.

Stock-Settled

Upon vesting, these restricted stock

units are settled by issuing one share of ConocoPhillips

common stock per

unit.

Units awarded to retirement

eligible employees vest six months

from the grant date; however,

those units

are not issued as common stock until

the earlier of separation from the company

or the end of the regularly

scheduled vesting period.

Until issued as stock, most recipients

of the restricted stock units receive

a cash

payment of a dividend equivalent or

an accrued reinvested dividend

equivalent that is charged to retained

earnings.

The grant date fair market

value of these restricted stock

units is deemed equal to the average

ConocoPhillips stock price on the grant

date.

The grant date fair market

value of units that do not receive a

dividend equivalent while unvested

is deemed equal to the average

ConocoPhillips stock price on the grant

date,

less the net present value of the dividends that

will not be received.

The following summarizes our stock

-settled stock unit activity for the year

ended December 31, 2021:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total

Fair Value

Outstanding at December 31, 2020

6,431,985

$

58.94

Granted

4,590,103

46.56

Forfeited

(566,047)

48.59

Issued

(2,810,730)

54.74

$

144

Outstanding at December 31, 2021

7,645,311

$

53.81

Not Vested at

December 31, 2021

5,509,133

53.81

At December 31, 2021, the remaining unrecognized

compensation cost from the unvested

stock-settled units was

$

126

million, which will be recognized over

a weighted-average

period of

1.67

years, the longest period being

2.59

years.

The weighted-average

grant date fair value

of stock unit awards granted

during 2020 and 2019 was $

57.40

and $

67.77

, respectively.

The total fair value of stock

units issued during 2020 and 2019 was $

143

million and

$

225

million, respectively.

Cash-Settled

Cash settled executive restricted

stock units granted in 2018 and

2019 replaced the stock option program.

These

restricted stock units, subject to

elections to defer,

will be settled in cash equal to the fair

market value of a share

of ConocoPhillips common stock per unit

on the settlement date and are classified

as liabilities on the balance

sheet.

Units awarded to retirement

eligible employees vest six months

from the grant date; however,

those units

are not settled until the earlier of separation

from the company or the end of the regularly

scheduled vesting

period.

Compensation expense is initially measured

using the average fair market

value of ConocoPhillips common

stock and is subsequently adjusted,

based on changes in the ConocoPhillips stock price through

the end of each

subsequent reporting period, through

the settlement date.

Recipients receive an accrued reinvested

dividend

equivalent that is charged to

compensation expense.

The accrued reinvested dividend

is paid at the time of

settlement, subject to the terms and

conditions of the award.

Beginning with executive restricted

stock units

granted in 2020 awards will be

settled in stock.

Notes to Consolidated Financial Statements

133

ConocoPhillips

2021 10-K

The following summarizes our cash

-settled stock unit activity for the year

ended December 31, 2021:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total

Fair Value

Outstanding at December 31, 2020

614,615

$

39.95

Granted

11,186

57.19

Forfeited

(2,927)

51.43

Issued

(396,398)

50.75

$

20

Outstanding at December 31, 2021

226,476

$

72.18

Not Vested at

December 31, 2021

59,443

72.18

At December 31, 2021, there was

no

remaining unrecognized compensation

cost to be recorded for the unvested

cash-settled units.

The weighted-average grant

date fair value of stock

unit awards granted during

2020 and 2019

were $

41.59

and $

68.20

, respectively.

The total fair value of stock

units issued during 2020 and 2019 were

negligible and $

6

million, respectively.

Performance Share Program

-Under the Plan, we also annually grant restricted

performance share units (PSUs) to

senior management.

These PSUs are authorized three years

prior to their effective grant

date (the performance

period).

Compensation expense is initially measured

using the average fair market

value of ConocoPhillips

common stock and is subsequently adjusted,

based on changes in the ConocoPhillips stock price through

the end

of each subsequent reporting period, through

the grant date for stock

-settled awards and the settlement

date for

cash-settled awards.

Stock-Settled

For performance periods beginning before

2009, PSUs do not vest until the employee becomes

eligible for

retirement by reaching age 55

with five years of service, and restrictions

do not lapse until the employee separates

from the company.

With respect to awards for performance

periods beginning in 2009 through 2012, PSUs do not

vest until the earlier of the date the employee

becomes eligible for retirement

by reaching age 55 with five years

of service or five years after the grant

date of the award, and restrictions

do not lapse until the earlier of the

employee's separation

from the company or five years

after the grant date (although

recipients can elect to defer

the lapsing of restrictions until separation).

We recognize compensation

expense for these awards

beginning on

the grant date and ending on the date

the PSUs are scheduled to vest.

Since these awards are authorized

three

years prior to the effective

grant date, for

employees eligible for retirement

by or shortly after the grant date,

we

recognize compensation expense

over the period beginning on the date of authorization

and ending on the date of

grant.

Until issued as stock, recipients of the PSUs receive

a quarterly cash payment of a dividend

equivalent that

is charged to retained earnings.

Beginning in 2013, PSUs authorized for future grants

will vest, absent employee

election to defer,

upon settlement following the conclusion

of the three-year performance period.

We recognize

compensation expense over the period beginning

on the date of authorization and

ending on the conclusion of the

performance period.

PSUs are settled by issuing one share

of ConocoPhillips common stock per unit.

The following summarizes our stock

-settled Performance Share

Program activity for the year ended

December 31, 2021:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total

Fair Value

Outstanding at December 31, 2020

1,736,728

$

50.56

Issued

(287,881)

49.91

$

18

Outstanding at December 31, 2021

1,448,847

$

50.69

Not Vested at

December 31, 2021

3,191

$

48.61

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

134

At December 31, 2021, there was

no

remaining unrecognized compensation

cost to be recorded on the unvested

stock-settled performance share

s.

The weighted-average grant

date fair value of stock-settled

PSUs granted

during 2020 and 2019 was $

58.61

and $

68.90

, respectively.

The total fair value of stock-settled

PSUs issued during

2020 and 2019 was $

13

million and $

25

million, respectively.

Cash-Settled

In connection with and immediately following

the separation of our Downstream

businesses in 2012, grants of new

PSUs, subject to a shortened performance period,

were authorized.

Once granted, these PSUs vest,

absent

employee election to defer,

on the earlier of five years after

the grant date of the award

or the date the employee

becomes eligible for retirement.

For employees eligible for retirement

by or shortly after the grant date,

we

recognize compensation expense

over the period beginning on the date of authorization

and ending on the date of

grant.

Otherwise, we recognize compensation

expense beginning on the grant

date and ending on the date the

PSUs are scheduled to vest.

These PSUs are settled in cash equal to the fair

market value of a share

of

ConocoPhillips common stock per unit on

the settlement date and thus are classified

as liabilities on the balance

sheet.

Until settlement occurs,

recipients of the PSUs receive a quarterly cash

payment of a dividend equivalent

that is charged to compensation expense.

Beginning in 2013, PSUs authorized for future

grants will vest upon settlement

following the conclusion of the

three-year performance period.

We recognize compensation

expense over the period beginning on the date

of

authorization and ending at the conclusion

of the performance period.

These PSUs will be settled in cash equal to

the fair market value of a share

of ConocoPhillips common stock per unit

on the settlement date and are

classified

as liabilities on the balance sheet.

For performance periods beginning before

2018, during the performance

period, recipients of the PSUs do not receive a

quarterly cash payment of a dividend

equivalent, but after the

performance period ends, until settlement

in cash occurs, recipients of the PSUs receive

a quarterly cash payment

of a dividend equivalent that is charged

to compensation expense.

For the performance period beginning in 2018,

recipients of the PSUs receive an accrued reinvested

dividend equivalent that is charged

to compensation expense.

The accrued reinvested dividend

is paid at the time of settlement, subject to the terms

and conditions of the

award.

The following summarizes our cash

-settled Performance Share

Program activity for the year ended

December 31, 2021:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total

Fair Value

Outstanding at December 31, 2020

124,529

$

39.95

Granted

1,073,228

46.65

Settled

(1,080,078)

48.13

$

52

Outstanding at December 31, 2021

117,679

$

72.18

At December 31, 2021, all outstanding

cash-settled performance awards

were fully vested and there was

no

remaining compensation cost to

be recorded.

The weighted-average

grant date fair value

of cash-settled PSUs

granted during 2020 and 2019 was $

58.61

and $

68.90

, respectively.

The total fair value of cash-settled

performance share awards

settled during 2020 and 2019 was $

116

million and $

171

million, respectively.

Notes to Consolidated Financial Statements

135

ConocoPhillips

2021 10-K

From inception of the Performance Share

Program through 2013,

approved PSU awards were

granted after the

conclusion of performance periods.

Beginning in February 2014, initial target PSU awards

are issued near the

beginning of new performance periods.

These initial target PSU awards

will terminate at the end of the

performance periods and will be settled after the

performance periods have ended.

Also in 2014, initial target PSU

awards were issued for open

performance periods that began in

prior years.

For the open performance period

beginning in 2012, the initial target PSU awards

terminated at the end of the three-year

performance period and

were replaced with approved

PSU awards.

For the open performance period beginning in

2013, the initial target

PSU awards terminated at

the end of the three-year performance period

and were settled after the performance

period ended.

There is no effect on recognition

of compensation expense.

Other

-In addition to the above active programs,

we have outstanding shares

of restricted stock and restricted

stock units that were either issued

as part of our non-employee director compensation

program for current

and

former members of the company's

Board of Directors,

as part of an executive compensation

program that has

been discontinued or acquired as a result

of an acquisition.

Generally, the recipients

of the restricted shares or

units receive a dividend or dividend equivalent.

The following summarizes the aggregate

activity of these restricted shares

and units for the year ended

December 31, 2021:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total

Fair Value

Outstanding at December 31, 2020

970,099

$

47.78

Granted

797,704

46.43

Cancelled

(1,948)

27.80

Issued

(149,488)

46.80

$

8

Outstanding at December 31, 2021

1,616,367

$

47.24

Not Vested at

December 31, 2021

695,958

$

45.87

At December 31, 2021, the remaining compensation

cost from the unvested

restricted stock was $

20

million,

which will be recognized over a weighted-average

period of

1.46

years, the longest period being

2

years. The

weighted-average

grant date fair value

of awards granted during

2020 and 2019 was $

51.46

and $

63.58

,

respectively.

The total fair value of awards

issued during 2020 and 2019 was $

6

million and $

11

million,

respectively.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

136

Note 17-Income Taxes

Components of income tax provision

(benefit) were:

Millions of Dollars

2021

2020

2019

Income Taxes

Federal

Current

$

32

3

18

Deferred

1,161

(625)

(113)

Foreign

Current

3,128

350

2,545

Deferred

66

(70)

(323)

State and local

Current

127

(4)

148

Deferred

119

(139)

(8)

Total

tax provision (benefit)

$

4,633

(485)

2,267

Deferred income taxes

reflect the net tax effect

of temporary differences

between the carrying amounts of

assets and liabilities for financial reporting purposes

and the amounts used for tax purposes.

Major components

of deferred tax liabilities and

assets at December 31 were:

Millions of Dollars

2021

2020

Deferred Tax

Liabilities

PP&E and intangibles

$

10,170

7,744

Inventory

44

64

Other

213

242

Total

deferred tax liabilities

10,427

8,050

Deferred Tax

Assets

Benefit plan accruals

321

540

Asset retirement obligations

and accrued environmental costs

2,297

2,262

Investments in joint ventures

1,684

1,653

Other financial accruals and deferrals

827

907

Loss and credit carryforwards

7,402

8,904

Other

399

365

Total

deferred tax assets

12,930

14,631

Less: valuation allowance

(8,342)

(9,965)

Total

deferred tax assets

net of valuation allowance

4,588

4,666

Net deferred tax liabilities

$

5,839

3,384

At December 31, 2021, noncurrent assets

and liabilities included deferred taxes

of $

340

million and $

6,179

million,

respectively.

At December 31, 2020, noncurrent assets

and liabilities included deferred taxes

of $

363

million and

$

3,747

million, respectively.

At December 31, 2021, the loss and credit carryforward

deferred tax assets

were primarily related to U.S.

foreign

tax credit carryforwards

of $

5.5

billion and various jurisdictions net operating

loss and credit carryforwards of $

1.9

billion.

If not utilized, U.S. foreign

tax credits and net operating

losses will begin to expire in 2022.

Our overall deferred

tax liability increased during 2021 by $

1.1

billion due to our Concho acquisition.

Notes to Consolidated Financial Statements

137

ConocoPhillips

2021 10-K

The following table shows a reconciliation

of the beginning and ending deferred tax

asset valuation allowance for

for 2021, 2020 and 2019:

Millions of Dollars

2021

2020

2019

Balance at January 1

$

9,965

10,214

3,040

Charged to expense (benefit)

(45)

460

(225)

Other*

(1,578)

(709)

7,399

Balance at December 31

$

8,342

9,965

10,214

*Represents changes due to originating deferred tax asset that have no impact to our effective tax rate, acquisitions/dispositions/revisions and

the effect of translating foreign financial statements.

Valuation allowances

have been established to

reduce deferred tax assets

to an amount that will, more likely than

not, be realized.

At December 31, 2021, we have maintained

a valuation allowance with respect to

substantially all

U.S. foreign tax credit

carryforwards as well as certain

net operating loss carryforwards

for various jurisdictions.

During 2021, the valuation allowance movement

charged to earnings primarily relates

to the fair value

measurement of our CVE common shares that

are not expected to be realized,

and the expected realization of

certain U.S. tax attributes

associated with our planned disposition of our Indonesia assets.

This is partially offset

by Australian tax benefits

associated with our impairment of APLNG that we do not

expect to be realized.

Other

movements are primarily related

to valuation allowances on expiring

tax attributes.

Based on our historical

taxable income, expectations

for the future, and available

tax-planning strategies, management

expects deferred

tax assets, net of valuation

allowances, will primarily be realized as offsets

to reversing deferred

tax liabilities.

For

more information on our pending Indonesia

disposition

see Note 3

During 2020, the valuation allowance movement

charged to earnings primarily related

to capital losses in Australia

and to the fair value measurement of our

CVE common shares that are not expected

to be realized.

Other

movements are primarily related

to valuation allowances on expiring

tax attributes.

On December 2, 2019, the Internal Revenue Service finalized

foreign tax credit regulations

related to the 2017 Tax

Cuts and Jobs Act.

Due to the finalization of these regulations,

in the fourth quarter of 2019 we recognized

$

151

million of net deferred tax

assets.

Correspondingly,

we recorded $

6,642

million of existing foreign tax

credit

carryovers where recognition

was previously considered to

be remote.

Present legislation still makes

their

realization unlikely and

therefore these credits have

been offset with a full valuation allowance.

At December 31, 2021, unremitted

income considered to be permanently reinvested

in certain foreign subsidiaries

and foreign corporate

joint ventures totaled

approximately $

4,384

million.

Deferred income taxes

have not been

provided on this amount, as we do not plan to

initiate any action that would require

the payment of income taxes.

The estimated amount of additional tax,

primarily local withholding tax, that would

be payable on this income if

distributed is approximately

$

219

million.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

138

The following table shows a reconciliation

of the beginning and ending unrecognized

tax benefits for 2021,

2020 and 2019:

Millions of Dollars

2021

2020

2019

Balance at January 1

$

1,206

1,177

1,081

Additions based on tax positions related

to the current year

15

6

9

Additions for tax positions of prior years

177

67

120

Reductions for tax positions

of prior years

(5)

(34)

(22)

Settlements

(9)

(9)

Lapse of statute

(48)

(1)

(2)

Balance at December 31

$

1,345

1,206

1,177

Included in the balance of unrecognized tax

benefits for 2021, 2020 and 2019 were $

1,261

million, $

1,128

million

and $

1,100

million, respectively,

which, if recognized, would impact our effective

tax rate.

The balance of the

unrecognized tax benefits

increased

in 2021 mainly due to U.S. tax credits acquired

through our Concho

acquisition.

The balance of the unrecognized tax benefits

increased in 2019 mainly due to the treatment

of our

PDVSA settlement.

and

At December 31, 2021, 2020 and 2019, accrued liabilities for

interest and penalties totaled $

47

million, $

46

million

and $

42

million, respectively,

net of accrued income taxes.

Interest and penalties resulted

in a reduction to

earnings of $

1

million in 2021, a reduction of $

4

million in 2020, and benefit to earnings of $

3

million in 2019.

We file tax returns

in the U.S. federal jurisdiction and

in many foreign and state

jurisdictions.

Audits in major

jurisdictions are generally complete as

follows: Canada (2016), U.S. (2017)

and Norway (2020).

Issues in dispute

for audited years and audits

for subsequent years are ongoing

and in various stages of completion in

the many

jurisdictions in which we operate around

the world.

Consequently,

the balance in unrecognized tax benefits

can

be expected to fluctuate from

period to period.

Within the next twelve months, we may

have audit periods close

that could significantly impact our total

unrecognized tax benefits.

It is reasonably possible such changes could be

significant when compared with our total

unrecognized tax benefits, but

the amount of change is not estimable.

In January 2022, the IRS closed the 2017 audit of our U.S. federal

income tax return.

As a result, in the first quarter

of 2022, we will recognize a previously

unrecognized $

475

million federal tax benefit

related to the recovery

of

outside tax basis previously offset

by a full reserve.

Notes to Consolidated Financial Statements

139

ConocoPhillips

2021 10-K

The amounts of U.S. and foreign income

(loss) before income taxes,

with a reconciliation of tax at

the federal

statutory rate

to the provision for income taxes,

were:

Millions of Dollars

Percent of Pre-Tax

Income (Loss)

2021

2020

2019

2021

2020

2019

Income (loss) before income taxes

United States

$

8,024

(3,587)

4,704

63.1

%

114.2

49.4

Foreign

4,688

447

4,820

36.9

(14.2)

50.6

$

12,712

(3,140)

9,524

100.0

%

100.0

100.0

Federal statutory

income tax

$

2,670

(659)

2,000

21.0

%

21.0

21.0

Non-U.S. effective tax

rates

1,915

194

1,399

15.1

(6.2)

14.7

Tax impact of debt

restructuring

75

0.6

Australia disposition

(349)

11.1

U.K. disposition

(732)

(7.7)

Recovery of outside basis

(55)

(22)

(77)

(0.4)

0.7

(0.8)

Adjustment to tax reserves

(11)

18

9

(0.1)

(0.6)

0.1

Adjustment to valuation allowance

(45)

460

(225)

(0.4)

(14.6)

(2.4)

State income tax

194

(112)

123

1.5

3.6

1.3

Malaysia Deepwater Incentive

(164)

(1.7)

Enhanced oil recovery credit

(99)

(6)

(27)

(0.8)

0.2

(0.3)

Other

(11)

(9)

(39)

(0.1)

0.3

(0.4)

Tota

l

$

4,633

(485)

2,267

36.4

%

15.5

23.8

Our effective tax rate

for 2021 was driven by our

jurisdictional tax rates for

this profit mix with net favorable

impacts from routine tax credits

and valuation allowance adjustments.

The valuation allowance adjustment is

primarily related to the fair value

measurement and disposition of our CVE common shares

of $

218

million and the

ability to utilize the U.S. foreign

tax credit and capital loss carryforward

due to our anticipated disposition

of our

Indonesia entities of $

29

million. This was partially offset by an increase

to our valuation allowance related

to the

tax impact of the impairment of our APLNG investment

of $

206

million for which we do not expect to receive

a tax

benefit.

Our effective tax rate

for 2020 was impacted by the disposition

of our Australia-West

assets as well as the

valuation allowance related

to the fair value measurement of our

CVE common shares.

The Australia-West

disposition generated a before-tax

gain of $

587

million with an associated tax benefit

of $

10

million and resulted in

the de-recognition of deferred

tax assets resulting in $

92

million of tax expense.

The disposition also generated an

Australia capital loss tax

benefit of $

313

million which has been fully offset by a valuation

allowance.

Due to

changes in the fair market value

of CVE common shares, the valuation allowance

was increased by $

178

million to

offset the expected capital

loss.

Our effective tax rate

for 2019 was favorably

impacted by the sale of two of our U.K. subsidiaries. The disposition

generated a before-tax

gain of more than $

1.7

billion with an associated tax

benefit of $

335

million. The

disposition generated a U.S.

capital loss of approximately

$

2.1

billion which has generated a U.S.

tax benefit of

approximately $

285

million. The remaining U.S. capital loss has

been recorded as a deferred

tax asset fully offset

with a valuation allowance.

During 2019, we received final partner approval

in Malaysia Block G to claim certain deepwater

tax credits.

As a

result, we recorded an income tax

benefit of $

164

million.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

140

Note 18-Accumulated Other Comprehensive

Loss

Accumulated other comprehensive

loss in the equity section of the balance sheet included:

Millions of Dollars

Defined

Benefit Plans

Net

Unrealized

Gain/(Loss)

on Securities

Foreign

Currency

Translation

Accumulated

Other

Comprehensive

Loss

December 31, 2018

$

(361)

(5,702)

(6,063)

Other comprehensive income (loss)

51

695

746

Cumulative effect of adopting

ASU No. 2018-02*

(40)

(40)

December 31, 2019

(350)

(5,007)

(5,357)

Other comprehensive income

(75)

2

212

139

December 31, 2020

(425)

2

(4,795)

(5,218)

Other comprehensive income (loss)

394

(2)

(124)

268

December 31, 2021

$

(31)

(4,919)

(4,950)

*We adopted ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income," beginning January 1,

During 2019, we recognized $

483

million of foreign currency translation

adjustments related to the completion

of

our sale of two ConocoPhillips U.K. subsidiaries.

The following table summarizes reclassifications

out of accumulated other comprehensive

loss during the years

ended December 31:

Millions of Dollars

2021

2020

Defined Benefit Plans

$

109

72

Above amounts are included in the computation of net periodic benefit cost and

are presented net of tax expense of:

$

31

13

See Note 16.

Notes to Consolidated Financial Statements

141

ConocoPhillips

2021 10-K

Note 19-Cash Flow Information

Millions of Dollars

2021

2020

2019

Noncash Investing Activities

Increase (decrease) in PP&E related to

an increase (decrease) in asset

retirement obligations

$

442

(116)

205

Cash Payments

Interest

$

924

785

810

Income taxes

856

905

2,905

Net Sales (Purchases) of Investments

Short-term investments

purchased

$

(5,554)

(12,435)

(4,902)

Short-term investments

sold

8,810

12,015

2,138

Investments and long-term receivables

purchased

(279)

(325)

(146)

Investments and long-term receivables

sold

114

87

$

3,091

(658)

(2,910)

The following items are included in the "Cash

Flows from Operating Activities" section

of our consolidated cash

flows.

In 2021, we made a total of $

297

million in contributions to our U.S. qualified

pension plan.

In 2019, we made a

$

324

million contribution to our U.K. pension

plan.

We collected $

330

million in 2019 from PDVSA under settlement

agreements related to an

award issued by the ICC

Tribunal in 2018.

For more information on these

settlements,

see Note 11

and

Note 12

for additional information on cash

and non-cash changes to our consolidated

balance

sheet associated with our Concho acquisition.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

142

Note 20-Other Financial Information

Millions of Dollars

2021

2020

2019

Interest and Debt Expense

Incurred

Debt

$

887

788

799

Other

59

73

36

946

861

835

Capitalized

(62)

(55)

(57)

Expensed

$

884

806

778

Other Income (Loss)

Interest income

$

33

100

166

Gain (loss) on investment in Cenovus

Energy*

1,040

(855)

649

Other, net

130

246

543

$

1,203

(509)

1,358

*See Note 5.

Research and Development Expenditures

-expensed

$

62

75

82

Shipping and Handling Costs

$

1,047

857

1,008

Foreign Currency Transaction

(Gains) Losses

-after-tax

Alaska

$

Lower 48

Canada

(1)

(7)

5

Europe, Middle East and North Africa

(11)

(15)

Asia Pacific

2

(11)

31

Other International

1

2

1

Corporate and Other

(7)

(31)

21

$

(16)

(62)

58

Millions of Dollars

2021

2020

Properties, Plants and Equipment

Proved properties*

$

114,274

**

94,312

Unproved properties*

10,993

4,141

Other

4,379

3,653

Gross properties, plants and equipment

129,646

102,106

Less: Accumulated depreciation,

depletion and amortization

(64,735)

**

(62,213)

Net properties, plants and equipment

$

64,911

39,893

*Proved and Unproved properties increased by $

20.0

billion and $

6.9

billion, respectively, in 2021 compared with 2020, primarily due to

the Concho and Shell Permian acquisitions.

**Excludes assets classified as held for sale at December 31, 2021.

Notes to Consolidated Financial Statements

143

ConocoPhillips

2021 10-K

Note 21-Related Party

Transactions

Our related parties primarily include equity method

investments and certain trusts

for the benefit of employees.

For disclosures on trusts for

the benefit of employees,

see Note 16

Significant transactions with our equity

affiliates were:

Millions of Dollars

2021

2020

2019

Operating revenues and other income

$

88

79

89

Purchases

5

38

Operating expenses and selling, general

and administrative expenses

196

63

65

Net interest income*

(2)

(5)

(13)

*We paid interest to, or received interest from, various affiliates.

See Note 4, for additional information on loans to

affiliated companies.

Note 22-Sales and Other Operating Revenues

Revenue from Contracts

with Customers

The following table provides further

disaggregation of our consolidated

sales and other operating revenues:

Millions of Dollars

2021

2020

2019

Revenue from contracts

with customers

$

34,590

13,662

26,106

Revenue from contracts

outside the scope of ASC Topic

606

Physical contracts

meeting the definition of a derivative

11,500

5,177

6,558

Financial derivative contracts

(262)

(55)

(97)

Consolidated sales and other operating

revenues

$

45,828

18,784

32,567

Revenues from contracts

outside the scope of ASC Topic

606 relate primarily to physical

gas contracts at market

prices which qualify as derivatives accounted

for under ASC Topic

815, "Derivatives and Hedging,"

and for which

we have not elected NPNS.

There is no significant difference

in contractual terms or the policy for

recognition of

revenue from these contracts

and those within the scope of ASC Topic

The following disaggregation

of

revenues is provided in conjunction

with

Note 23-Segment Disclosures and Related Information

:

Millions of Dollars

2021

2020

2019

Revenue from Outside the Scope of ASC Topic

606

by Segment

Lower 48

$

9,050

3,966

4,989

Canada

1,457

727

691

Europe, Middle East and North Africa

993

484

878

Physical contracts

meeting the definition of a derivative

$

11,500

5,177

6,558

Millions of Dollars

2021

2020

2019

Revenue from Outside the Scope of ASC Topic

606

by Product

Crude oil

$

757

395

804

Natural gas

10,034

4,339

5,313

Other

709

443

441

Physical contracts

meeting the definition of a derivative

$

11,500

5,177

6,558

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

144

Practical Expedients

Typically,

our commodity sales contracts are

less than 12 months in duration; however,

in certain specific cases

may extend longer,

which may be out to the end of field life.

We have long-term commodity sales contracts which

use prevailing market prices at the time of delivery, and under these contracts, the market-based variable

consideration for each performance obligation (i.e., delivery of commodity) is allocated to each wholly unsatisfied

performance obligation within the contract.

Accordingly,

we have applied the practical expedient allowed in ASC

Topic 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations

or when we expect to recognize revenues that are unsatisfied (or partially unsatisfied) as of the end of the

reporting period.

Receivables and Contract

Liabilities

Receivables from Contracts with Customers

At December 31, 2021, the "Accounts

and notes receivable" line on our consolidated

balance sheet included trade

receivables of $

5,268

million compared with $

1,827

million at December 31, 2020, and included both contracts

with customers within the scope of ASC Topic

606 and those that are outside the scope of ASC Topic

We

typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made.

Revenues that are outside the scope

of ASC Topic 606 relate

primarily to physical gas sales contracts

at market

prices for which we do not elect NPNS and are

therefore accounted

for as a derivative under ASC Topic

There

is little distinction in the nature of the customer

or credit quality of trade receivables

associated with gas sold

under contracts for which NPNS

has not been elected compared with trade

receivables where NPNS has been

elected.

Contract Liabilities from Contracts with Customers

We have entered into contractual arrangements where we license proprietary technology to customers related to

the optimization process for operating LNG plants. The agreements typically provide for negotiated payments to

be made at stated milestones. The payments are not directly related to our performance under the contract and

are recorded as deferred revenue to be recognized as revenue when the customer can utilize and benefit from

their right to use the license. Payments are received in installments over the construction period.

Millions of Dollars

Contract Liabilities

At December 31, 2020

$

97

Contractual payments received

15

Revenue recognized

(62)

At December 31, 2021

$

50

Amounts Recognized in the Consolidated

Balance Sheet at December 31, 2021

Current liabilities

$

50

We expect to recognize the contract liabilities as of December 31, 2021, as revenue during 2022.

Notes to Consolidated Financial Statements

145

ConocoPhillips

2021 10-K

Note 23-Segment Disclosures and Related

Information

We explore for,

produce, transport and market

crude oil, bitumen, natural gas,

LNG and NGLs on a worldwide

basis.

We manage our operations

through

six

operating segments, which are primarily defined

by geographic

region: Alaska; Lower 48; Canada; Europe,

Middle East and North Africa; Asia Pacific; and

Other International.

Corporate and Other represents

income and costs not directly associated

with an operating segment, such as most

interest expense, premiums

on early retirement of debt, corporate

overhead and certain technology activities,

including licensing revenues.

Corporate assets include all cash

and cash equivalents and short-term investments.

We evaluate performance

and allocate resources based

on net income (loss) attributable to ConocoPhillips.

Segment accounting policies are the same as those

in

Note 1

Intersegment sales are at

prices that approximate

market.

In 2021, we completed our acquisition of Concho,

an independent oil and gas exploration

and production company

with operations across New Mexico

and West Texas

as well as our acquisition of Shell's

Permian assets in the Texas

Delaware Basin.

The accounting close date of the Shell transaction

,

used for reporting purposes, was December

31, 2021.

Results of operations for

Concho and assets acquired from Shell are included in

our Lower 48 segment.

Certain transaction and restructuring

costs associated with these acquisitions

are included in our Corporate and

Other segment.

Analysis of Results by Operating Segment

Millions of Dollars

2021

2020

2019

Sales and Other Operating Revenues

Alaska

$

5,480

3,408

5,483

Intersegment eliminations

(11)

Alaska

5,480

3,397

5,483

Lower 48

29,306

9,872

15,514

Intersegment eliminations

(12)

(51)

(46)

Lower 48

29,294

9,821

15,468

Canada

4,077

1,666

2,910

Intersegment eliminations

(1,583)

(405)

(1,141)

Canada

2,494

1,261

1,769

Europe, Middle East and North Africa

5,902

1,919

5,101

Intersegment eliminations

(2)

Europe, Middle East and North Africa

5,902

1,917

5,101

Asia Pacific

2,579

2,363

4,525

Other International

4

7

Corporate and Other

75

18

221

Consolidated sales and other operating

revenues

$

45,828

18,784

32,567

The market for our products

is large and diverse, therefore,

our sales and other operating revenues

are not

dependent upon any single customer.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

146

Millions of Dollars

2021

2020

2019

Depreciation, Depletion, Amortization

and Impairments

Alaska

$

1,002

996

805

Lower 48

4,067

3,358

3,224

Canada

392

342

232

Europe, Middle East and North Africa

862

775

887

Asia Pacific

1,483

809

1,285

Other International

Corporate and Other

76

54

62

Consolidated depreciation, depletion,

amortization and impairments

$

7,882

6,334

6,495

Equity in Earnings of Affiliates

Alaska

$

5

(7)

7

Lower 48

(18)

(11)

(159)

Canada

Europe, Middle East and North Africa

502

311

470

Asia Pacific

343

137

461

Other International

2

Corporate and Other

Consolidated equity in earnings of affiliates

$

832

432

779

Income Tax

Provision (Benefit)

Alaska

$

402

(256)

472

Lower 48

1,390

(378)

137

Canada

150

(185)

(43)

Europe, Middle East and North Africa

2,543

136

1,425

Asia Pacific

483

294

501

Other International

(53)

(20)

8

Corporate and Other

(282)

(76)

(233)

Consolidated income tax provision

(benefit)

$

4,633

(485)

2,267

Net Income (Loss) Attributable

to ConocoPhillips

Alaska

$

1,386

(719)

1,520

Lower 48

4,932

(1,122)

436

Canada

458

(326)

279

Europe, Middle East and North Africa

1,167

448

3,170

Asia Pacific

453

962

1,483

Other International

(107)

(64)

263

Corporate and Other

(210)

(1,880)

38

Consolidated net income (loss) attributable

to ConocoPhillips

$

8,079

(2,701)

7,189

Notes to Consolidated Financial Statements

147

ConocoPhillips

2021 10-K

Millions of Dollars

2021

2020

2019

Investments in and Advances to

Affiliates

Alaska

$

58

62

83

Lower 48

242

25

35

Canada

Europe, Middle East and North Africa

797

918

1,070

Asia Pacific

5,603

6,705

7,265

Other International

1

Corporate and Other

Consolidated investments

in and advances to affiliates

$

6,701

7,710

8,453

Total Assets

Alaska

$

14,812

14,623

15,453

Lower 48

41,699

11,932

14,425

Canada

7,439

6,863

6,350

Europe, Middle East and North Africa

9,125

8,756

9,269

Asia Pacific

9,840

11,231

13,568

Other International

1

226

285

Corporate and Other

7,745

8,987

11,164

Consolidated total assets

$

90,661

62,618

70,514

Capital Expenditures and Investments

Alaska

$

982

1,038

1,513

Lower 48

3,129

1,881

3,394

Canada

203

651

368

Europe, Middle East and North Africa

534

600

708

Asia Pacific

390

384

584

Other International

33

121

8

Corporate and Other

53

40

61

Consolidated capital expenditures

and investments

$

5,324

4,715

6,636

Interest Income and Expense

Interest income

Alaska

$

Lower 48

Canada

Europe, Middle East and North Africa

2

5

11

Asia Pacific

9

7

6

Other International

Corporate and Other

22

88

149

Interest and debt expense

Corporate and Other

$

884

806

778

Sales and Other Operating Revenues

by Product

Crude oil

$

23,648

9,736

18,482

Natural gas

16,904

6,427

8,715

Natural gas liquids

1,668

528

814

Other*

3,608

2,093

4,556

Consolidated sales and other operating

revenues by product

$

45,828

18,784

32,567

*Includes LNG and bitumen.

Notes to Consolidated Financial Statements

ConocoPhillips

2021 10-K

148

Geographic Information

Millions of Dollars

Sales and Other Operating Revenues

(1)

Long-Lived Assets

(2)

2021

2020

2019

2021

2020

2019

United States

$

34,847

13,230

21,159

50,580

24,034

26,566

Australia and Timor-Leste

605

1,647

5,579

6,676

7,228

Canada

2,494

1,261

1,769

6,608

6,385

5,769

China

724

460

772

1,476

1,491

1,447

Indonesia

(3)

879

689

875

28

464

605

Libya

1,102

155

1,103

659

670

668

Malaysia

975

610

1,230

1,252

1,501

1,871

Norway

2,563

1,426

2,349

4,681

5,294

5,258

United Kingdom

2,236

336

1,649

1

1

2

Other foreign countries

8

12

14

748

1,087

1,308

Worldwide consolidated

$

45,828

18,784

32,567

71,612

47,603

50,722

(1) Sales and other operating revenues are attributable to countries based on the location of the selling operation.

(2) Defined as net PP&E plus equity investments and advances to affiliated companies.

(3) Met held for sale criteria in 2021 in conjunction with our agreement to sell our subsidiary holding

our Indonesia assets.

Supplementary Data

149

ConocoPhillips

2021 10-K

Oil and Gas Operations

(Unaudited)

In accordance with FASB

ASC Topic

932, "Extractive Activities-Oil and Gas,"

and regulations of the SEC, we are

making certain supplemental disclosures

about our oil and gas exploration and

production operations.

These disclosures include information about

our consolidated oil and gas activities and our proportionate

share of

our equity affiliates' oil and gas

activities in our operating segments.

As a result, amounts reported as equity

affiliates in Oil and Gas Operations

may differ from those shown in the

individual segment disclosures reported

elsewhere in this report.

Our disclosures by geographic

area include the U.S., Canada, Europe, Asia Pacific/Middle

East (inclusive of equity affiliates)

,

and Africa.

As required by current authoritative

guidelines, the estimated future date

when an asset will be permanently shut

down for economic reasons is based on

historical 12-month

first-of-month average

prices and current costs.

This

estimated date when production

will end 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, which are

reported under the "economic

interest" method, as well as variable-royalty

regimes, and are subject to fluctuations

in commodity prices,

recoverable operating

expenses and capital costs.

If costs remain stable, reserve quantities

attributable to

recovery of costs will change inversely

to changes in commodity prices.

For example, if prices increase, then

our

applicable reserve quantities would decline.

At December 31, 2021, approximately

4 percent of our total proved

reserves were under PSCs, located

in our Asia Pacific/Middle East geographic

reporting area, and 5 percent of our

total proved reserves

were under a variable-royalty

regime, located in our Canada geographic

reporting area.

Reserves Governance

The recording and reporting of proved

reserves are governed by criteria

established by regulations of the SEC

and

FASB.

Proved reserves are those

quantities of oil and gas, which, by analysis

of geoscience and engineering data,

can be estimated with reasonable certainty

to be economically producible-from a

given date forward,

from

known reservoirs, and under existing

economic conditions, operating methods,

and government regulations-prior

to the time at which contracts providing

the right to operate expire, unless

evidence indicates renewal is

reasonably certain, regardless

of whether deterministic or probabilistic

methods are used for the estimation.

The

project to extract the hydrocarbons

must have commenced or the operator

must be reasonably certain it will

commence the project within a reasonable time.

Proved reserves are further classified

as either developed or undeveloped.

Proved developed reserves are

proved

reserves that can be expected to

be recovered through existing

wells with existing equipment and operating

methods, or in which the cost of the required equipment

is relatively minor compared

with the cost of a new well,

and through installed extraction

equipment and infrastructure operational

at the time of the reserves estimate if

the extraction is by means not involving

a well.

Proved undeveloped reserves are

proved reserves expected

to be

recovered from new wells

on undrilled acreage, or from existing

wells where a relatively major expenditure

is

required for recompletion. Reserves

on undrilled acreage are limited to those

directly offsetting development

spacing areas that are reasonably

certain of production when drilled, unless evidence provided

by reliable

technologies exists that establishes

reasonable certainty of economic producibility

at greater distances.

As defined

by SEC regulations, reliable technologies

may be used in reserve estimation when

they have been demonstrated

in

the field to provide reasonably certain

results with consistency and repeatability

in the formation being evaluated

or in an analogous formation. The technologies

and data used in the estimation of our proved

reserves include, but

are not limited to,

performance-based methods, volumetric

-based methods, geologic maps, seismic interpretation,

well logs, well test data, core

data, analogy and statistical

analysis.

Supplementary Data

ConocoPhillips

2021 10-K

150

We have a company

-wide, comprehensive, SEC-compliant

internal policy that governs

the determination and

reporting of proved reserves.

This policy is applied by the geoscientists and

reservoir engineers in our business

units around the world.

As part of our internal control process,

each business unit's reserves processes

and

controls are reviewed

annually by an internal team which is headed by

the company's Manager of Reserves

Compliance and Reporting.

This team, composed of internal reservoir

engineers, geoscientists, finance personnel

and a senior representative

from DeGolyer and MacNaughton (D&M), a third

-party petroleum engineering

consulting firm, reviews the business

units' reserves for adherence to SEC

guidelines and company policy through

on-site visits, teleconferences

and review of documentation.

In addition to providing independent reviews,

this

internal team also ensures reserves

are calculated using consistent

and appropriate standards

and procedures.

This team is independent of business unit line management

and is responsible for reporting its findings

to senior

management.

The team is responsible for communicating

our reserves policy and procedures

and is available for

internal peer reviews and consultation

on major projects or technical issues throughout

the year.

All of our proved

reserves held by consolidated companies

and our share of equity affiliates have

been estimated by ConocoPhillips.

During 2021, our processes and controls

used to assess over 90 percent of proved

reserves as of December 31,

2021, were reviewed by D&M.

The purpose of their review was to assess whether

the adequacy and effectiveness

of our internal processes and controls

used to determine estimates of proved

reserves are in accordance with SEC

regulations.

In such review,

ConocoPhillips' technical staff

presented D&M with an overview of the reserves

data,

as well as the methods and assumptions used in estimating

reserves.

The data presented included pertinent

seismic information, geologic maps,

well logs, production tests, material

balance calculations, reservoir simulation

models, well performance data, operating

procedures and relevant economic

criteria.

Management's intent

in

retaining D&M to review its processes

and controls was to provide

objective third-party input on these processes

and controls.

D&M's opinion was the general

processes and controls

employed by ConocoPhillips in estimating its

December 31, 2021, proved reserves for

the properties reviewed are in

accordance with the SEC reserves

definitions.

D&M's report is

included as Exhibit 99 of this Annual Report on Form 10-K.

The technical person primarily responsible

for overseeing the processes and

internal controls used in the

preparation of the company's

reserves estimates is the Manager of Reserves

Compliance and Reporting.

This

individual holds a master's degree in petroleum

engineering.

He is a member of the Society of Petroleum

Engineers with over 25 years of oil and

gas industry experience and has held positions of increasing

responsibility

in reservoir engineering, subsurface and asset

management in the U.S. and several

international field locations.

Engineering estimates of the quantities of proved

reserves are inherently imprecise.

See the "Critical Accounting

Estimates" section of Management's

Discussion and Analysis of Financial Condition and Results

of Operations for

additional discussion of the sensitivities surrounding these

estimates.

Supplementary Data

151

ConocoPhillips

2021 10-K

Proved Reserves

Years Ended

Crude Oil

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

Developed and Undeveloped

Consolidated operations

End of 2018

1,233

703

1,936

4

246

159

188

2,533

Revisions

40

(36)

4

(1)

18

(5)

23

39

Improved recovery

7

7

7

Purchases

1

1

1

Extensions and discoveries

25

226

251

2

11

264

Production

(74)

(95)

(169)

(36)

(31)

(14)

(250)

Sales

(2)

(2)

(30)

(32)

End of 2019

1,231

797

2,028

5

198

134

197

2,562

Revisions

(297)

(126)

(423)

(2)

4

(4)

(3)

(428)

Improved recovery

3

3

Purchases

5

5

3

8

Extensions and discoveries

10

108

118

3

121

Production

(65)

(77)

(142)

(2)

(28)

(25)

(3)

(200)

Sales

(14)

(14)

(1)

(15)

End of 2020

879

693

1,572

6

174

108

191

2,051

Revisions

209

(52)

157

2

14

37

6

216

Improved recovery

1

1

1

Purchases

691

691

691

Extensions and discoveries

10

289

299

5

2

1

307

Production

(64)

(160)

(224)

(3)

(29)

(24)

(13)

(293)

Sales

(9)

(9)

(9)

End of 2021

1,035

1,452

2,487

10

161

122

184

2,964

Equity affiliates

End of 2018

78

78

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

(5)

Sales

End of 2019

73

73

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

(5)

Sales

End of 2020

68

68

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

(5)

Sales

End of 2021

63

63

Total

company

End of 2018

1,233

703

1,936

4

246

237

188

2,611

End of 2019

1,231

797

2,028

5

198

207

197

2,635

End of 2020

879

693

1,572

6

174

176

191

2,119

End of 2021

1,035

1,452

2,487

10

161

185

184

3,027

Supplementary Data

ConocoPhillips

2021 10-K

152

Years Ended

Crude Oil

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

Developed

Consolidated operations

End of 2018

1,058

346

1,404

2

192

113

185

1,896

End of 2019

1,048

334

1,382

3

149

94

181

1,809

End of 2020

765

263

1,028

6

129

77

175

1,415

End of 2021

912

916

1,828

4

122

98

171

2,223

Equity affiliates

End of 2018

78

78

End of 2019

73

73

End of 2020

68

68

End of 2021

63

63

Undeveloped

Consolidated operations

End of 2018

175

357

532

2

54

46

3

637

End of 2019

183

463

646

2

49

40

16

753

End of 2020

114

430

544

45

31

16

636

End of 2021

123

536

659

6

39

24

13

741

Equity affiliates

End of 2018

End of 2019

End of 2020

End of 2021

Notable changes in proved crude oil reserves

in the three years ended December 31, 2021,

included:

●

Revisions

: In 2021, Alaska upward revisions

were primarily driven by higher prices.

Downward revisions in Lower 48 were

due to development timing for specific well

locations from unconventional

plays of 203 million barrels and technical

revisions of 35 million barrels, partially offset

by upward revisions due to

higher prices of 115 million barrels and additional

infill drilling in the unconventional plays

of 71 million barrels.

Upward revisions in Europe were

primarily due to higher

prices. In Asia Pacific/Middle East,

increases were due to higher prices of 21 million barrels

and technical revisions of 16

million barrels.

In 2020, Alaska downward revisions

were primarily driven by lower prices of 243 million barrels

and development plan

changes of 54 million barrels.

Downward revisions in Lower

48 were due to lower prices of 89 million barrels

and

development timing for specific well locations

from unconventional plays

of 82 million barrels, partially offset by upward

technical revisions and additional infill drilling

in the unconventional plays

of 45 million barrels.

In 2019, Alaska upward revisions

were due to cost and technical revisions

of 74 million barrels, partially offset by downward

price revisions of 34 million barrels.

Upward revisions in Europe and

Africa were primarily due to infill drilling and technical

revisions.

Downward revisions in Lower 48 were

due to changes in development timing for

specific well locations from the

unconventional plays

of 71 million barrels and price revisions of 22 million barrels, partially

offset by upward revisions

related to infill drilling and improved

well performance of 57 million barrels.

Supplementary Data

153

ConocoPhillips

2021 10-K

●

Purchases

:

In 2021, Lower 48 purchases were due to

the Concho and Shell Permian acquisitions.

●

Extensions and discoveries

: In 2021, extensions and discoveries in Lower

48 were due to planned development

to add

specific well locations from the unconventional

plays which more than offset the decreases

resulting from development

plan timing in the revisions category.

In 2020, extensions and discoveries in Lower

48 were due to planned development

to add specific well locations from

the

unconventional plays

which more than offset the decreases resulting

from development plan timing in the revisions

category.

In 2019, extensions and discoveries in Lower

48 were due to planned development

to add specific well locations from

the

unconventional plays

which more than offset the decreases in the revisions

category.

In Asia Pacific/Middle East, increases

were due to sanctioning of development

programs in China and Malaysia.

●

Sales

: In 2019, Europe sales represent the disposition

of the U.K. assets.

Supplementary Data

ConocoPhillips

2021 10-K

154

Years Ended

Natural Gas Liquids

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Total

Developed and Undeveloped

Consolidated operations

End of 2018

106

222

328

1

17

3

349

Revisions

(1)

(11)

(12)

3

(1)

(10)

Improved recovery

Purchases

Extensions and discoveries

62

62

1

63

Production

(5)

(28)

(33)

(3)

(1)

(37)

Sales

(4)

(4)

End of 2019

100

245

345

2

13

1

361

Revisions

(26)

(26)

1

(1)

(26)

Improved recovery

Purchases

2

2

2

4

Extensions and discoveries

41

41

1

42

Production

(6)

(27)

(33)

(1)

(2)

(36)

Sales

(5)

(5)

(5)

End of 2020

94

230

324

4

12

340

Revisions

(6)

213

207

1

208

Improved recovery

Purchases

72

72

72

Extensions and discoveries

82

82

2

84

Production

(6)

(50)

(56)

(1)

(2)

(59)

Sales

(1)

(1)

(1)

End of 2021

82

546

628

5

11

644

Equity affiliates

End of 2018

42

42

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(3)

(3)

Sales

End of 2019

39

39

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(3)

(3)

Sales

End of 2020

36

36

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(3)

(3)

Sales

End of 2021

33

33

Total

company

End of 2018

106

222

328

1

17

45

391

End of 2019

100

245

345

2

13

40

400

End of 2020

94

230

324

4

12

36

376

End of 2021

82

546

628

5

11

33

677

Supplementary Data

155

ConocoPhillips

2021 10-K

Years Ended

Natural Gas Liquids

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Total

Developed

Consolidated operations

End of 2018

106

97

203

15

3

221

End of 2019

100

99

199

1

10

1

211

End of 2020

94

83

177

4

9

190

End of 2021

82

334

416

3

9

428

Equity affiliates

End of 2018

42

42

End of 2019

39

39

End of 2020

36

36

End of 2021

33

33

Undeveloped

Consolidated operations

End of 2018

125

125

1

2

128

End of 2019

146

146

1

3

150

End of 2020

147

147

3

150

End of 2021

212

212

2

2

216

Equity affiliates

End of 2018

End of 2019

End of 2020

End of 2021

Notable changes in proved NGL reserves

in the three years ended December 31,

2021, included:

●

Revisions

: In 2021, upward revisions

in Lower 48 were due to conversion

of acquired Concho Permian two-stream

contracts

to a three-stream (crude oil, natural

gas and natural gas liquids) basis,

adding 182 million barrels, additional infill drilling in

the unconventional plays

of 44 million barrels, technical revisions

of 21 million barrels and higher prices of 28 million

barrels, partially offset by downward

revisions related to development

timing for specific well locations

from

unconventional plays

of 62 million barrels.

In 2020, downward revisions in Lower

48 were due to lower prices of 33 million barrels

and development timing for specific

well locations from unconventional

plays of 20 million barrels, partially offset

by upward technical revisions

and additional

infill drilling in the unconventional plays

of 27 million barrels.

In 2019, downward revisions in Lower

48 were due to changes in development

timing for specific well locations from

the

unconventional plays

of 32 million barrels and price revisions of 11 million barrels, partially

offset by upward revisions

related to infill drilling and improved

well performance of 32 million barrels.

●

Purchases

: In 2021, Lower 48 purchases were due to

the Shell Permian acquisition.

●

Extensions and discoveries

: In 2021, extensions and discoveries in Lower

48 were due to planned development

to add

specific well locations from the unconventional

plays which more than offset the decreases

in the revisions category.

In 2020, extensions and discoveries in Lower

48 were due to planned development

to add specific well locations from

the

unconventional plays

,

which more than offset the decreases in the revisions

category.

In 2019, extensions and discoveries in Lower

48 were due to planned development

to add specific well locations from

the

unconventional plays

,

which more than offset the decreases in the revisions

category.

●

Sales

: In 2019, Europe sales represent the disposition

of the U.K. assets.

Supplementary Data

ConocoPhillips

2021 10-K

156

Years Ended

Natural Gas

December 31

Billions of Cubic Feet

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

Developed and Undeveloped

Consolidated operations

End of 2018

2,736

2,318

5,054

26

1,212

1,079

214

7,585

Revisions

30

(113)

(83)

(2)

160

147

21

243

Improved recovery

Purchases

2

2

2

Extensions and discoveries

7

483

490

23

1

514

Production

(85)

(252)

(337)

(4)

(178)

(250)

(11)

(780)

Sales

(7)

(7)

(298)

(305)

End of 2019

2,688

2,431

5,119

43

896

977

224

7,259

Revisions

(607)

(439)

(1,046)

(15)

39

103

2

(917)

Improved recovery

Purchases

74

74

29

103

Extensions and discoveries

304

304

33

2

339

Production

(85)

(231)

(316)

(16)

(112)

(171)

(2)

(617)

Sales

(39)

(39)

(58)

(97)

End of 2020

1,996

2,100

4,096

74

825

851

224

6,070

Revisions

715

41

756

15

54

60

885

Improved recovery

Purchases

2,438

2,438

2,438

Extensions and discoveries

822

822

46

2

870

Production

(86)

(473)

(559)

(30)

(113)

(147)

(7)

(856)

Sales

(270)

(270)

(270)

End of 2021

2,625

4,658

7,283

105

768

764

217

9,137

Equity affiliates

End of 2018

4,564

4,564

Revisions

(7)

(7)

Improved recovery

Purchases

Extensions and discoveries

252

252

Production

(388)

(388)

Sales

End of 2019

4,421

4,421

Revisions

(382)

(382)

Improved recovery

Purchases

2

2

Extensions and discoveries

78

78

Production

(395)

(395)

Sales

End of 2020

3,724

3,724

Revisions

247

247

Improved recovery

Purchases

Extensions and discoveries

116

116

Production

(390)

(390)

Sales

End of 2021

3,697

3,697

Total

company

End of 2018

2,736

2,318

5,054

26

1,212

5,643

214

12,149

End of 2019

2,688

2,431

5,119

43

896

5,398

224

11,680

End of 2020

1,996

2,100

4,096

74

825

4,575

224

9,794

End of 2021

2,625

4,658

7,283

105

768

4,461

217

12,834

Supplementary Data

157

ConocoPhillips

2021 10-K

Years Ended

Natural Gas

December 31

Billions of Cubic Feet

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

Developed

Consolidated operations

End of 2018

2,720

1,427

4,147

17

1,052

758

214

6,188

End of 2019

2,601

1,398

3,999

30

697

843

224

5,793

End of 2020

1,961

1,051

3,012

74

598

806

224

4,714

End of 2021

2,579

3,100

5,679

52

679

688

217

7,315

Equity affiliates

End of 2018

4,059

4,059

End of 2019

3,898

3,898

End of 2020

3,293

3,293

End of 2021

3,204

3,204

Undeveloped

Consolidated operations

End of 2018

16

891

907

9

160

321

1,397

End of 2019

87

1,033

1,120

13

199

134

1,466

End of 2020

35

1,049

1,084

227

45

1,356

End of 2021

46

1,558

1,604

53

89

76

1,822

Equity affiliates

End of 2018

505

505

End of 2019

523

523

End of 2020

431

431

End of 2021

493

493

Natural gas production

in the reserves table may differ

from gas production (delivered

for sale) in our statistics

disclosure, primarily

because the quantities above include gas

consumed in production operations.

Quantities consumed in production operations

are

not significant in the periods presented.

The value of net production consumed

in operations is not reflected in net revenues

and

production expenses, nor do the volumes impact the respective

per unit metrics.

Reserve volumes include natural gas

to be consumed in operations of 2,748 Bcf,

2,286 Bcf and 3,141 Bcf, as

of December 31, 2021,

2020 and 2019, respectively.

These volumes are not included in the calculation of our

Standardized Measure of Discounted

Future

Net Cash Flows Relating to Proved

Oil and Gas Reserve Quantities.

Natural gas reserves are

computed at 14.65 pounds per square inch absolute

and 60 degrees Fahrenheit.

Notable changes in proved natural

gas reserves in the three years

ended December 31, 2021, included:

●

Revisions

: In 2021, upward revisions

in Alaska were due to higher prices of 587 Bcf and technical

revisions of 128 Bcf.

In

Lower 48, upward revisions of 614 Bcf were

due to higher prices, additional infill drilling in the unconventional

plays of 277

Bcf and technical revisions of 60 Bcf,

partially offset by downward

revisions due to development timing for

specific well

locations from unconventional

plays of 498 Bcf and conversion

of previously acquired Permian two-stream

contracted

volumes to a three-stream (crude

oil, natural gas and natural

gas liquids) basis of 412 Bcf.

Upward revisions in Canada were

due to higher prices of 29 Bcf, partially

offset by downward revisions

due to technical revisions of 14 Bcf.

In Europe,

upward revisions were primarily

due to higher prices.

Upward revisions in our consolidated

operations in Asia

Pacific/Middle East were due

to technical revisions of 76 Bcf,

partially offset by price revisions

of 16 Bcf.

In our equity

affiliates in Asia Pacific/Middle East,

upward revisions were due

to higher prices of 124 Bcf and technical and cost

revisions

of 123 Bcf.

In 2020,

downward revisions in Alaska

were primarily due to lower prices.

In Lower 48, downward revisions

of 372 Bcf were

due to lower prices and 154 Bcf were due to development

timing for specific well locations from

unconventional plays,

partially offset by technical revisions

of 87 Bcf.

Downward revisions in our

equity affiliates in Asia Pacific/Middle East

were

Supplementary Data

ConocoPhillips

2021 10-K

158

due to lower prices of 426 Bcf,

partially offset by performance revisions

of 44 Bcf.

Upward revisions

in our consolidated

operations in Asia Pacific/Middle East

were due to technical revisions

of 88 Bcf and price revisions of 15 Bcf.

In 2019, upward revisions in Europe

were due to technical and cost

revisions.

In Asia Pacific/Middle East upward

revisions

were primarily due to the Indonesia Corridor PSC term

extension.

Downward revisions in Lower 48 were

due to changes in

development timing for specific well locations

from the unconventional plays

of 207 Bcf and price revisions of 125 Bcf,

partially offset by upward

revisions related to infill drilling

and improved well performance of 219 Bcf.

●

Purchases

: In 2021, Lower 48 purchases were due to

the Concho and Shell Permian acquisitions.

In 2020, Canada purchases were due to the acquisition

of additional Montney acreage.

●

Extensions and discoveries

: In 2021, extensions and discoveries in Lower

48 were due to planned development

to add

specific well locations from the unconventional

plays which more than offset the decreases

resulting from development

plan timing in the revisions category.

Extensions and discoveries in Canada were primarily

driven by ongoing drilling

successes in Montney.

In 2020,

extensions and discoveries in Lower

48 were due to planned development

to add specific well locations from

the

unconventional plays

which more than offset the decreases resulting

from development plan timing in the revisions

category.

Extensions and discoveries in Canada were primarily

driven by ongoing drilling successes in Montney.

In 2019, extensions and discoveries in Lower

48 were due to planned development

to add specific well locations from

the

unconventional plays

which more than offset the decreases in the revisions

category.

Extensions and discoveries in our

equity affiliates were due to ongoing

development in APLNG.

●

Sales

: In 2021, Lower 48 sales represent the disposition

of noncore assets.

In 2020, Asia Pacific/Middle East sales

represent the disposition of the Australia

-West assets.

In 2019, Europe sales represent the disposition

of the U.K. assets.

Supplementary Data

159

ConocoPhillips

2021 10-K

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed and Undeveloped

Consolidated operations

End of 2018

236

Revisions

37

Improved recovery

Purchases

Extensions and discoveries

31

Production

(22)

Sales

End of 2019

282

Revisions

(15)

Improved recovery

Purchases

Extensions and discoveries

85

Production

(20)

Sales

End of 2020

332

Revisions

(50)

Improved recovery

Purchases

Extensions and discoveries

Production

(25)

Sales

End of 2021

257

Equity affiliates

End of 2018

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

Sales

End of 2019

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

Sales

End of 2020

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

Sales

End of 2021

Total

company

End of 2018

236

End of 2019

282

End of 2020

332

End of 2021

257

Supplementary Data

ConocoPhillips

2021 10-K

160

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed

Consolidated operations

End of 2018

155

End of 2019

187

End of 2020

117

End of 2021

150

Equity affiliates

End of 2018

End of 2019

End of 2020

End of 2021

Undeveloped

Consolidated operations

End of 2018

81

End of 2019

95

End of 2020

215

End of 2021

107

Equity affiliates

End of 2018

End of 2019

End of 2020

End of 2021

Notable changes in proved bitumen reserves

in the three years ended December 31, 2021,

included:

●

Revisions

: In 2021, downward revisions

of 64 million barrels were driven by changes in carbon

tax costs

and 39 million barrels due to changes in development

timing for specific pad locations from the Surmont

development program, partially

offset by upward revisions

from price of 53 million barrels.

In 2020,

downward revisions in Canada

were due to changes in development

timing for specific pad

locations from the Surmont development

program of 12 million barrels

with the remaining revisions

primarily related to lower prices.

In 2019, upward revisions in Canada were

due to technical revisions in

Surmont of 70 million barrels,

partially offset by downward

revisions due to changes in development

timing for specific pad locations

from the Surmont development program

of 31 million barrels.

●

Extensions and discoveries

: In 2020,

extensions and discoveries in

Canada were primarily due to planned

development to add specific pad locations

from the Surmont development program,

which more than

offset the decrease in the revisions

category.

In 2019, extensions and discoveries in Canada

were due to planned development to

add specific pad

locations from the Surmont development

program, which offset

the decrease in the revisions category

of

31 million barrels.

Supplementary Data

161

ConocoPhillips

2021 10-K

Years Ended

Total Proved

Reserves

December 31

Millions of Barrels of Oil Equivalent

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

Developed and Undeveloped

Consolidated operations

End of 2018

1,795

1,312

3,107

245

465

342

224

4,383

Revisions

44

(67)

(23)

36

48

19

26

106

Improved recovery

7

7

7

Purchases

2

2

2

Extensions and discoveries

26

368

394

38

11

443

Production

(93)

(165)

(258)

(23)

(68)

(74)

(16)

(439)

Sales

(3)

(3)

(85)

(88)

End of 2019

1,779

1,447

3,226

296

360

298

234

4,414

Revisions

(398)

(226)

(624)

(20)

12

13

(3)

(622)

Improved recovery

3

3

Purchases

19

19

10

29

Extensions and discoveries

10

200

210

95

305

Production

(85)

(142)

(227)

(25)

(49)

(55)

(3)

(359)

Sales

(25)

(25)

(1)

(10)

(36)

End of 2020

1,306

1,273

2,579

355

323

249

228

3,734

Revisions

322

168

490

(45)

23

47

6

521

Improved recovery

1

1

1

Purchases

1,169

1,169

1,169

Extensions and discoveries

10

508

518

15

3

1

537

Production

(84)

(289)

(373)

(35)

(50)

(48)

(14)

(520)

Sales

(54)

(54)

(54)

End of 2021

1,555

2,775

4,330

290

299

249

220

5,388

Equity affiliates

End of 2018

880

880

Revisions

(1)

(1)

Improved recovery

Purchases

Extensions and discoveries

42

42

Production

(73)

(73)

Sales

End of 2019

848

848

Revisions

(63)

(63)

Improved recovery

Purchases

Extensions and discoveries

13

13

Production

(73)

(73)

Sales

End of 2020

725

725

Revisions

42

42

Improved recovery

Purchases

Extensions and discoveries

19

19

Production

(73)

(73)

Sales

End of 2021

713

713

Total

company

End of 2018

1,795

1,312

3,107

245

465

1,222

224

5,263

End of 2019

1,779

1,447

3,226

296

360

1,146

234

5,262

End of 2020

1,306

1,273

2,579

355

323

974

228

4,459

End of 2021

1,555

2,775

4,330

290

299

962

220

6,101

Supplementary Data

ConocoPhillips

2021 10-K

162

Years Ended

Total Proved

Reserves

December 31

Millions of Barrels of Oil Equivalent

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

Developed

Consolidated operations

End of 2018

1,617

681

2,298

160

382

244

221

3,305

End of 2019

1,582

666

2,248

197

275

236

218

3,174

End of 2020

1,186

521

1,707

140

238

211

212

2,508

End of 2021

1,424

1,767

3,191

166

244

212

207

4,020

Equity affiliates

End of 2018

796

796

End of 2019

761

761

End of 2020

653

653

End of 2021

631

631

Undeveloped

Consolidated operations

End of 2018

178

631

809

85

83

98

3

1,078

End of 2019

197

781

978

99

85

62

16

1,240

End of 2020

120

752

872

215

85

38

16

1,226

End of 2021

131

1,008

1,139

124

55

37

13

1,368

Equity affiliates

End of 2018

84

84

End of 2019

87

87

End of 2020

72

72

End of 2021

82

82

Natural gas reserves are

converted to barrels of oil equivalent

(BOE) based on a 6:1 ratio: six MCF of natural

gas converts to

one

BOE.

Proved Undeveloped Reserves

The following table shows changes

in total proved undeveloped

reserves for 2021:

Proved Undeveloped Reserves

Millions of Barrels of

Oil Equivalent

End of 2020

1,298

Revisions

(167)

Improved recovery

1

Purchases

158

Extensions and discoveries

448

Sales

Transfers

to proved developed

(288)

End of 2021

1,450

Downward revisions were

driven by changes in development timing

of 389 MMBOE primarily in North America and negative

bitumen revisions in Canada due to changes in

carbon tax costs of 65 MMBOE, partially offset

by upward revisions for

Lower 48 infill

drilling of 162 MMBOE and higher prices of 125 MMBOE.

Purchases were driven by Lower 48 due to

the Concho acquisition.

Supplementary Data

163

ConocoPhillips

2021 10-K

Extensions and discoveries were largely

driven by an addition of 399 MMBOE in Lower 48 for

the continued development of

unconventional plays.

The remaining extensions and discoveries were

driven by the continued development

planned in the other

geographic regions.

Transfers

to proved developed reserves

were driven by the ongoing development

of our assets. Approximately

65 percent of the

transfers were

from the development of our Lower 48 unconventional

plays. The remainder of transfers

were from development

across the other geographic regions.

At December 31, 2021, our PUDs represented

24 percent of total proved

reserves, compared with 29 percent at

December 31, 2020.

Costs incurred for the year ended

December 31, 2021, relating to the development

of PUDs were $3.8 billion.

A portion of our costs

incurred each year relates to development

projects where the PUDs will be converted

to proved developed reserves

in future years.

At the end of 2021, approximately

93 percent of total PUDs were under development

or scheduled for development

within five

years of initial disclosure, including all of our Lower

48 PUDs. The remaining PUDs are in major development

areas which are

currently producing and within our Canada

and Asia Pacific/Middle East geographic

areas.

Results of Operations

The company's results

of operations from oil and gas

activities for the years 2021, 2020 and 2019 are

shown in the following tables.

Non-oil and gas activities, such as pipeline and marine operations,

LNG operations, crude oil and gas marketing

activities, and the

profit element of transportation

operations in which we have an

ownership interest are

excluded.

Additional information about

selected line items within the results of operations

tables is shown below:

●

Sales include sales to unaffiliated entities attributable

primarily to the company's

net working interests and royalty

interests.

Sales are net of fees to transport

our produced hydrocarbons

beyond the production function to

a final delivery

point using transportation operations

which are not consolidated.

●

Transportation

costs reflect fees to transport

our produced hydrocarbons

beyond the production function to a

final delivery

point using transportatio

n

operations which are consolidated.

●

Other revenues include gains and losses

from asset sales, certain amounts resulting from

the purchase and sale of

hydrocarbons, and other miscellaneous

income.

●

Production costs include costs incurred

to operate and maintain

wells, related equipment and facilities

used in the

production of petroleum liquids and natural

gas.

●

Taxes

other than income taxes include

production, property and other non-income taxes.

●

Depreciation of support equipment is reclassified as

applicable.

●

Other related expenses include inventory

fluctuations, foreign currency transaction

gains and losses and other

miscellaneous expenses.

Supplementary Data

ConocoPhillips

2021 10-K

164

Results of Operations

Year Ended

Millions of Dollars

December 31, 2021

Lower

Total

Asia Pacific/

Other

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

Consolidated operations

Sales

$

4,832

14,093

18,925

1,219

3,568

2,525

917

27,154

Transfers

4

4

4

Transportation costs

(626)

(626)

(626)

Other revenues

14

135

149

323

(5)

237

141

(161)

684

Total revenues

4,224

14,228

18,452

1,542

3,563

2,762

1,058

(161)

27,216

Production costs excluding taxes

1,073

2,414

3,487

518

487

466

43

5,001

Taxes

other than income taxes

442

937

1,379

23

36

91

1

1

1,531

Exploration expenses

80

98

178

39

21

51

2

15

306

Depreciation, depletion and

amortization

864

4,053

4,917

383

844

787

35

6,966

Impairments

5

(8)

(3)

6

(24)

7

(14)

Other related expenses

(31)

12

(19)

(22)

(42)

4

4

12

(63)

Accretion

71

47

118

10

70

26

224

1,720

6,675

8,395

585

2,171

1,330

973

(189)

13,265

Income tax provision (benefit)

378

1,467

1,845

145

1,673

494

870

(53)

4,974

Results of operations

$

1,342

5,208

6,550

440

498

836

103

(136)

8,291

Equity affiliates

Sales

$

745

745

Transfers

1,797

1,797

Transportation costs

Other revenues

5

5

Total revenues

2,547

2,547

Production costs excluding taxes

329

329

Taxes

other than income taxes

824

824

Exploration expenses

268

268

Depreciation, depletion and

amortization

593

593

Impairments

718

718

Other related expenses

3

3

Accretion

17

17

(205)

(205)

Income tax provision (benefit)

(42)

(42)

Results of operations

$

(163)

(163)

Supplementary Data

165

ConocoPhillips

2021 10-K

Year Ended

Millions of Dollars

December 31, 2020

Lower

Total

Asia Pacific/

Other

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

Consolidated operations

Sales

$

2,944

3,421

6,365

230

1,560

1,717

129

10,001

Transfers

4

4

191

195

Transportation costs

(587)

(587)

(19)

(606)

Other revenues

(1)

(20)

(21)

40

(21)

576

11

10

595

Total revenues

2,360

3,401

5,761

270

1,539

2,465

140

10

10,185

Production costs excluding taxes

1,058

1,399

2,457

366

417

478

21

2

3,741

Taxes

other than income taxes

296

263

559

16

30

42

3

1

651

Exploration expenses

1,099

73

1,172

40

52

71

13

108

1,456

Depreciation, depletion and

amortization

840

2,544

3,384

335

755

808

8

5,290

Impairments

804

804

3

5

812

Other related expenses

46

5

51

5

(58)

(25)

(29)

2

(54)

Accretion

72

46

118

8

73

33

232

(1,051)

(1,733)

(2,784)

(503)

265

1,058

124

(103)

(1,943)

Income tax provision (benefit)

(271)

(430)

(701)

(191)

116

277

88

(20)

(431)

Results of operations

$

(780)

(1,303)

(2,083)

(312)

149

781

36

(83)

(1,512)

Equity affiliates

Sales

$

483

483

Transfers

1,205

1,205

Transportation costs

Other revenues

8

8

Total revenues

1,696

1,696

Production costs excluding taxes

289

289

Taxes

other than income taxes

502

502

Exploration expenses

20

20

Depreciation, depletion and

amortization

569

569

Impairments

Other related expenses

(2)

(2)

Accretion

15

15

303

303

Income tax provision (benefit)

39

39

Results of operations

$

264

264

Supplementary Data

ConocoPhillips

2021 10-K

166

Year Ended

Millions of Dollars

December 31, 2019

Lower

Total

Asia Pacific/

Other

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

Consolidated operations

Sales

$

4,883

6,356

11,239

709

3,207

3,032

919

19,106

Transfers

4

4

449

453

Transportation costs

(629)

(629)

(41)

(670)

Other revenues

61

78

139

86

1,785

12

101

326

2,449

Total revenues

4,319

6,434

10,753

795

4,992

3,452

1,020

326

21,338

Production costs excluding taxes

1,235

1,578

2,813

380

741

619

70

(8)

4,615

Taxes

other than income taxes

308

437

745

18

32

54

3

(2)

850

Exploration expenses

97

430

527

32

69

80

5

33

746

Depreciation, depletion and

amortization

700

2,804

3,504

230

842

1,172

37

5,785

Impairments

402

402

2

1

405

Other related expenses

(12)

116

104

(38)

(42)

58

22

10

114

Accretion

62

49

111

7

142

43

303

1,929

618

2,547

164

3,207

1,426

883

293

8,520

Income tax provision (benefit)

444

147

591

(74)

591

458

833

7

2,406

Results of operations

$

1,485

471

1,956

238

2,616

968

50

286

6,114

Equity affiliates

Sales

$

599

599

Transfers

2,229

2,229

Transportation costs

Other revenues

31

31

Total revenues

2,859

2,859

Production costs excluding taxes

335

335

Taxes

other than income taxes

820

820

Exploration expenses

Depreciation, depletion and

amortization

579

579

Impairments

Other related expenses

11

11

Accretion

16

16

1,098

1,098

Income tax provision (benefit)

170

170

Results of operations

$

928

928

Supplementary Data

167

ConocoPhillips

2021 10-K

Statistics

Net Production

2021

2020

2019

Thousands of Barrels Daily

Crude Oil

Consolidated operations

Alaska

178

181

202

Lower 48

447

213

266

United States

625

394

468

Canada

8

6

1

Europe

81

78

100

Asia Pacific

65

69

85

Africa

37

8

38

Total

consolidated operations

816

555

692

Equity affiliates-

Asia Pacific/Middle East

13

13

13

Total

company

829

568

705

Delaware Basin Area (Lower 48)*

162

28

24

Greater Prudhoe Area (Alaska)*

67

68

66

Natural Gas Liquids

Consolidated operations

Alaska

16

16

15

Lower 48

110

74

81

United States

126

90

96

Canada

4

2

Europe

4

4

7

Asia Pacific

1

4

Total

consolidated operations

134

97

107

Equity affiliates-

Asia Pacific/Middle East

8

8

8

Total

company

142

105

115

Delaware Basin Area (Lower 48)*

27

11

11

Greater Prudhoe Area (Alaska)*

16

15

15

Bitumen

Consolidated operations-

Canada

69

55

60

Total

company

69

55

60

Natural Gas

Millions of Cubic Feet Daily

Consolidated operations

Alaska

16

10

7

Lower 48

1,340

585

622

United States

1,356

595

629

Canada

80

40

9

Europe

298

270

447

Asia Pacific

360

429

637

Africa

15

5

31

Total

consolidated operations

2,109

1,339

1,753

Equity affiliates-

Asia Pacific/Middle East

1,053

1,055

1,052

Total

company

3,162

2,394

2,805

Delaware Basin Area (Lower 48)*

584

99

86

Greater Prudhoe Area (Alaska)*

12

4

4

*At year-end 2021, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves. At year-end 2021, 2020

and 2019, the Greater Prudhoe Area in Alaska contained more than 15 percent of our total proved reserves.

Supplementary Data

ConocoPhillips

2021 10-K

168

Average Sales Prices

2021

2020

2019

Crude Oil Per Barrel

Consolidated operations

Alaska*

$

60.81

33.72

55.85

Lower 48

66.12

35.17

55.30

United States

64.53

34.48

55.54

Canada

56.38

23.57

40.87

Europe

68.94

42.80

65.12

Asia Pacific

70.36

42.84

65.02

Africa

69.06

48.64

64.47

Total

international

68.85

42.39

64.85

Total

consolidated operations

65.53

36.69

58.51

Equity affiliates

-Asia Pacific/Middle East

69.45

39.02

61.32

Total

operations

65.59

36.75

58.57

Natural Gas Liquids Per Barrel

Consolidated operations

Lower 48

$

30.63

12.13

16.83

United States

30.63

12.13

16.85

Canada

31.18

5.41

19.87

Europe

43.97

23.27

29.37

Asia Pacific

33.21

37.85

Total

international

37.50

20.25

32.29

Total

consolidated operations

31.04

12.90

18.73

Equity affiliates

-Asia Pacific/Middle East

54.16

32.69

36.70

Total

operations

32.45

14.61

20.09

Bitumen Per Barrel

Consolidated operations-

Canada

$

37.52

8.02

**

31.72

Natural Gas Per Thousand Cubic Feet

Consolidated operations

Alaska

$

2.81

2.91

3.19

Lower 48

4.38

1.65

2.12

United States

4.38

1.66

2.12

Canada

2.54

1.21

0.49

Europe

13.75

3.23

4.92

Asia Pacific*

6.56

5.27

5.73

Africa

3.73

3.71

4.87

Total

international

8.91

4.31

5.35

Total

consolidated operations

6.00

3.13

4.19

Equity affiliates

-Asia Pacific/Middle East

5.31

3.71

6.29

Total

operations

5.77

3.38

4.99

*Average sales prices for Alaska crude oil and Asia Pacific natural gas above reflect a reduction for transportation costs in which we

have an ownership interest that are incurred subsequent to the terminal point of the production function.

Accordingly, the average sales prices

differ from those discussed in Item 7 of Management's Discussion and Analysis of Financial

Condition and Results of Operations.

**Average sales prices include unutilized transportation costs.

Supplementary Data

169

ConocoPhillips

2021 10-K

2021

2020

2019

Average Production Costs

Per Barrel of Oil Equivalent*

Consolidated operations

Alaska

$

14.92

14.60

15.52

Lower 48

8.48

9.93

9.59

United States

9.78

11.51

11.52

Canada

15.10

14.29

16.53

Europe

9.88

8.97

11.22

Asia Pacific

10.21

9.26

8.74

Africa

2.95

6.38

4.46

Total

international

10.53

10.11

10.26

Total

consolidated operations

9.99

10.99

10.99

Equity affiliates-

Asia Pacific/Middle East

4.60

4.01

4.68

Average Production Costs

Per Barrel-Bitumen

Consolidated operations-

Canada

$

13.41

12.45

13.74

Taxes

Other Than Income Taxes

Per Barrel of Oil Equivalent

Consolidated operations

Alaska

$

6.15

4.08

3.87

Lower 48

3.29

1.87

2.65

United States

3.87

2.62

3.05

Canada

0.67

0.62

0.78

Europe

0.73

0.65

0.48

Asia Pacific

1.99

0.81

0.76

Africa

0.07

0.91

0.19

Total

international

1.06

0.72

0.60

Total

consolidated operations

3.06

1.91

2.03

Equity affiliates-

Asia Pacific/Middle East

11.52

6.96

11.46

Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent

Consolidated operations

Alaska

$

12.02

11.59

8.80

Lower 48

14.24

18.05

17.03

United States

13.79

15.86

14.35

Canada

11.16

13.08

10.00

Europe

17.13

16.24

12.75

Asia Pacific

17.25

15.66

16.55

Africa

2.40

2.43

2.36

Total

international

14.25

15.01

12.99

Total

consolidated operations

13.92

15.54

13.78

Equity affiliates-

Asia Pacific/Middle East

8.29

7.89

8.09

*Includes bitumen.

Supplementary Data

ConocoPhillips

2021 10-K

170

Development and Exploration Activities

The following two tables summarize

our net interest in productive

and dry exploratory and development

wells in

the years ended December 31, 2021, 2020 and 2019.

A "development well"

is a well drilled within the proved area

of a reservoir to the depth of a stratigraphic

horizon known to be productive.

An "exploratory

well" is a well drilled

to find and produce crude oil or natural

gas in an unknown field or a new reservoir within a proven

field.

Exploratory wells also include wells drilled in areas

near or offsetting current production,

or in areas where well

density or production history have

not achieved statistical certainty

of results.

Excluded from the exploratory

well

count are stratigraphic

-type exploratory wells, primarily relating

to oil sands delineation wells located in Canada

and CBM test wells located in Asia

Pacific/Middle East.

Net Wells Completed

Productive

Dry

2021

2020

2019

2021

2020

2019

Exploratory

Consolidated operations

Alaska

7

1

3

Lower 48

87

3

35

6

United States

87

3

42

1

3

6

Canada

12

23

Europe

1

1

Asia Pacific/Middle East

1

1

Africa

Other areas

Total

consolidated operations

99

26

44

1

3

8

Equity affiliates

Asia Pacific/Middle East

3

8

8

Total

equity affiliates

3

8

8

Development

Consolidated operations

Alaska

1

7

12

Lower 48

339

127

255

United States

340

134

267

Canada

2

2

Europe

7

7

6

Asia Pacific/Middle East

21

16

21

Africa

1

2

2

Other areas

Total

consolidated operations

371

159

298

Equity affiliates

Asia Pacific/Middle East

30

109

106

Total

equity affiliates

30

109

106

*Our total proportionate interest was less than one.

Supplementary Data

171

ConocoPhillips

2021 10-K

The table below represents the status

of our wells drilling at December 31, 2021, and includes wells in the

process of drilling or in active completion.

It also represents gross and net

productive wells, including producing

wells and wells capable of production at

December 31, 2021.

Wells at December 31, 2021

Productive

In Progress

Oil

Gas

Gross

Net

Gross

Net

Gross

Net

Consolidated operations

Alaska

2

1

1,602

940

Lower 48

665

337

16,306

8,015

5,091

2,211

United States

667

338

17,908

8,955

5,091

2,211

Canada

18

15

186

94

149

149

Europe

11

1

494

84

59

2

Asia Pacific/Middle East

15

7

351

166

38

18

Africa

7

1

858

140

10

2

Other areas

Total

consolidated operations

718

362

19,797

9,439

5,347

2,382

Equity affiliates

Asia Pacific/Middle East

130

25

4,908

1,171

Total

equity affiliates

130

25

4,908

1,171

Acreage at December 31, 2021

Thousands of Acres

Developed

Undeveloped

Gross

Net

Gross

Net

Consolidated operations

Alaska

663

479

1,341

1,329

Lower 48

4,096

2,538

10,514

8,233

United States

4,759

3,017

11,855

9,562

Canada

297

219

3,433

1,948

Europe

430

50

938

371

Asia Pacific/Middle East

921

421

10,451

6,930

Africa

358

58

12,545

2,049

Other areas

156

125

Total

consolidated operations

6,765

3,765

39,378

20,985

Equity affiliates

Asia Pacific/Middle East

1,039

248

3,807

856

Total equity

affiliates

1,039

248

3,807

856

Supplementary Data

ConocoPhillips

2021 10-K

172

Costs Incurred

Year Ended

Millions of Dollars

December 31

Lower

Total

Asia Pacific/

Other

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

2021

Consolidated operations

Unproved property acquisition

$

1

11,261

11,262

4

11,266

Proved property acquisition

16,101

16,101

1

16,102

1

27,362

27,363

5

27,368

Exploration

84

765

849

80

31

51

2

40

1,053

Development

949

2,461

3,410

175

398

433

24

4,440

$

1,034

30,588

31,622

260

429

484

26

40

32,861

Equity affiliates

Unproved property acquisition

$

Proved property acquisition

Exploration

5

5

Development

21

21

$

26

26

2020

Consolidated operations

Unproved property acquisition

$

4

10

14

378

3

9

404

Proved property acquisition

62

62

129

191

4

72

76

507

3

9

595

Exploration

287

116

403

218

110

32

4

38

805

Development

745

1,758

2,503

102

451

427

18

3,501

$

1,036

1,946

2,982

827

561

462

22

47

4,901

Equity affiliates

Unproved property acquisition

$

Proved property acquisition

Exploration

12

12

Development

282

282

$

294

294

2019

Consolidated operations

Unproved property acquisition

$

101

45

146

14

197

357

Proved property acquisition

1

116

117

115

232

102

161

263

14

115

197

589

Exploration

281

390

671

200

119

66

8

39

1,103

Development

1,125

3,028

4,153

215

625

486

22

5,501

$

1,508

3,579

5,087

429

744

667

30

236

7,193

Equity affiliates

Unproved property acquisition

$

62

62

Proved property acquisition

62

62

Exploration

23

23

Development

171

171

$

256

256

Supplementary Data

173

ConocoPhillips

2021 10-K

Capitalized Costs

At December 31

Millions of Dollars

Lower

Total

Asia Pacific/

Other

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

2021

Consolidated operations

Proved property

$

22,750

58,561

81,311

7,380

14,514

12,226

966

116,397

Unproved property

1,402

7,704

9,106

1,517

155

92

114

9

10,993

24,152

66,265

90,417

8,897

14,669

12,318

1,080

9

127,390

Accumulated depreciation,

depletion and amortization

11,945

29,975

41,920

2,749

10,166

9,240

422

9

64,506

$

12,207

36,290

48,497

6,148

4,503

3,078

658

62,884

Equity affiliates

Proved property

$

10,357

10,357

Unproved property

2,162

2,162

12,519

12,519

Accumulated depreciation,

depletion and amortization

8,539

8,539

$

3,980

3,980

2020

Consolidated operations

Proved property

$

21,819

37,452

59,271

7,255

14,931

11,913

942

94,312

Unproved property

1,398

631

2,029

1,529

151

89

114

229

4,141

23,217

38,083

61,300

8,784

15,082

12,002

1,056

229

98,453

Accumulated depreciation,

depletion and amortization

11,098

27,948

39,046

2,431

10,015

8,567

387

9

60,455

$

12,119

10,135

22,254

6,353

5,067

3,435

669

220

37,998

Equity affiliates

Proved property

$

10,310

10,310

Unproved property

2,187

2,187

12,497

12,497

Accumulated depreciation,

depletion and amortization

6,959

6,959

$

5,538

5,538

Supplementary Data

ConocoPhillips

2021 10-K

174

Standardized Measure of

Discounted Future Net Cash Flows Relatin

g

to Proved Oil and Gas Reserve Quantities

In accordance with SEC and FASB

requirements, amounts were

computed using 12-month average

prices (adjusted only for existing

contractual terms) and end-of-year

costs, appropriate statutory

tax rates and a prescri

bed 10 percent discount factor.

Twelve-

month average prices are calculated

as the unweighted arithmetic average

of the first-day-of-the-month

price for each month within

the 12-month period prior to the end of the reporting period.

For all years, continuation of year

-end economic conditions was

assumed.

The calculations were based on estimates

of proved reserves, which are revised

over time as new data becomes available.

Probable or possible reserves, which may become

proved in the future, were not considered.

The calculations also require

assumptions as to the timing of future production

of proved reserves and the timing and amount

of future development costs,

including dismantlement, and future production

costs, including taxes other than

income taxes.

While due care was taken in

its preparation, we do not represent

that this data is the fair value of our

oil and gas properties, or a fair

estimate of the present value

of cash flows to be obtained from their development

and production.

Discounted Future Net Cash Flows

Millions of Dollars

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

2021

Consolidated operations

Future cash inflows

$

65,910

125,197

191,107

10,847

21,670

11,583

15,778

250,985

Less:

Future production costs

34,444

43,034

77,478

4,960

6,090

4,987

801

94,316

Future development costs

8,033

13,386

21,419

923

3,960

1,314

413

28,029

Future income tax provisions

5,310

13,167

18,477

117

8,345

1,542

13,506

41,987

Future net cash flows

18,123

55,610

73,733

4,847

3,275

3,740

1,058

86,653

10 percent annual discount

7,963

22,290

30,253

1,639

696

930

440

33,958

Discounted future net cash flows

$

10,160

33,320

43,480

3,208

2,579

2,810

618

52,695

Equity affiliates

Future cash inflows

$

27,851

27,851

Less:

Future production costs

15,491

15,491

Future development costs

1,649

1,649

Future income tax provisions

3,071

3,071

Future net cash flows

7,640

7,640

10 percent annual discount

2,640

2,640

Discounted future net cash flows

$

5,000

5,000

Total

company

Discounted future net cash flows

$

10,160

33,320

43,480

3,208

2,579

7,810

618

57,695

Supplementary Data

175

ConocoPhillips

2021 10-K

Millions of Dollars

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada*

Europe

Middle East

Africa

Total

2020

Consolidated operations

Future cash inflows

$

30,145

31,533

61,678

4,198

9,857

7,940

9,997

93,670

Less:

Future production costs

22,905

17,582

40,487

4,316

4,770

3,838

1,277

54,688

Future development costs

7,932

12,799

20,731

750

3,688

1,289

461

26,919

Future income tax provisions

376

376

267

1,075

7,571

9,289

Future net cash flows

(692)

776

84

(868)

1,132

1,738

688

2,774

10 percent annual discount

(1,501)

(820)

(2,321)

(396)

117

406

294

(1,900)

Discounted future net cash flows

$

809

1,596

2,405

(472)

1,015

1,332

394

4,674

Equity affiliates

Future cash inflows

$

17,284

17,284

Less:

Future production costs

10,239

10,239

Future development costs

1,186

1,186

Future income tax provisions

1,728

1,728

Future net cash flows

4,131

4,131

10 percent annual discount

1,269

1,269

Discounted future net cash flows

$

2,862

2,862

Total

company

Discounted future net cash flows

$

809

1,596

2,405

(472)

1,015

4,194

394

7,536

*Undiscounted future net cash flows related to the proved oil and gas reserves disclosed for Canada for the year ending

December 31, 2020, are negative due to the

inclusion of asset retirement costs and certain indirect costs in the calculation of the standardized measure of discounted future net cash flows. These costs are not

required to be included in the economic limit test for proved developed reserves as defined in Regulation S-X Rule 4-10.

Future net cash flows for Canada were also

impacted by lower 12-month average pricing for bitumen and crude oil in 2020.

Commodity prices have since improved in the current environment.

Supplementary Data

ConocoPhillips

2021 10-K

176

Millions of Dollars

Lower

Total

Asia Pacific/

Alaska

48

U.S.

Canada

Europe

Middle East

Africa

Total

2019

Consolidated operations

Future cash inflows

$

70,341

53,400

123,741

8,244

16,919

13,084

15,582

177,570

Less:

Future production costs

40,464

22,194

62,658

4,525

5,843

5,162

1,314

79,502

Future development costs

9,721

14,083

23,804

577

4,143

2,179

484

31,187

Future income tax provisions

3,904

2,793

6,697

4,201

1,931

12,747

25,576

Future net cash flows

16,252

14,330

30,582

3,142

2,732

3,812

1,037

41,305

10 percent annual discount

6,571

4,311

10,882

1,198

558

835

460

13,933

Discounted future net cash flows

$

9,681

10,019

19,700

1,944

2,174

2,977

577

27,372

Equity affiliates

Future cash inflows

$

31,671

31,671

Less:

Future production costs

16,157

16,157

Future development costs

1,218

1,218

Future income tax provisions

3,086

3,086

Future net cash flows

11,210

11,210

10 percent annual discount

4,040

4,040

Discounted future net cash flows

$

7,170

7,170

Total

company

Discounted future net cash flows

$

9,681

10,019

19,700

1,944

2,174

10,147

577

34,542

Supplementary Data

177

ConocoPhillips

2021 10-K

Sources of Change in Discounted

Future Net Cash Flows

Millions of Dollars

Consolidated Operations

Equity Affiliates

Total Company

2021

2020

2019

2021

2020

2019

2021

2020

2019

Discounted future net cash flows

at the beginning of the year

$

4,674

27,372

35,434

2,862

7,170

7,929

7,536

34,542

43,363

Changes during the year

Revenues less production

costs for the year

(20,000)

(5,198)

(13,424)

(1,389)

(897)

(1,673)

(21,389)

(6,095)

(15,097)

Net change in prices and

production costs

50,956

(34,307)

(13,538)

3,822

(4,769)

(422)

54,778

(39,076)

(13,960)

Extensions, discoveries and

improved recovery,

less

estimated future costs

10,420

887

2,985

(44)

22

260

10,376

909

3,245

Development costs for the year

4,396

3,593

5,333

91

192

239

4,487

3,785

5,572

Changes in estimated future

development costs

(33)

754

559

(104)

(205)

(21)

(137)

549

538

Purchases of reserves in place,

less estimated future costs

17,833

1

10

(3)

17,833

(2)

10

Sales of reserves in place,

less estimated future costs

(468)

(302)

(1,997)

(468)

(302)

(1,997)

Revisions of previous quantity

estimates

2,985

(2,299)

2,099

178

(42)

69

3,163

(2,341)

2,168

Accretion of discount

964

3,984

5,144

344

804

869

1,308

4,788

6,013

Net change in income taxes

(19,032)

10,189

4,767

(760)

590

(80)

(19,792)

10,779

4,687

Total changes

48,021

(22,698)

(8,062)

2,138

(4,308)

(759)

50,159

(27,006)

(8,821)

Discounted future net cash flows

at year end

$

52,695

4,674

27,372

5,000

2,862

7,170

57,695

7,536

34,542

●

The net change in prices and production costs

is the beginning-of-year reserve-production

forecast multiplied by the net annual

change in the per-unit sales price and production

cost, discounted at 10 percent.

●

Purchases and sales of reserves in place, along with extensions,

discoveries and improved recovery,

are calculated using

production forecasts

of the applicable reserve quantities for the year

multiplied by the 12-month average

sales prices, less

future estimated costs, discounted

at 10 percent.

●

Revisions of previous quantity estimates

are calculated using production

forecast changes for

the year,

including changes in the

timing of production, multiplied by the 12-month average

sales prices, less future estimated costs,

discounted at 10 percent.

●

The accretion of discount is 10 percent of the prior

year's discounted future

cash inflows, less future production

and

development costs.

●

The net change in income taxes

is the annual change in the discounted future

income tax provisions.

ConocoPhillips

2021 10-K

178

Item 9.

Changes in and Disagreements with Accountants on Accounting and

Financial Disclosure

None.

Item 9A. Controls and Procedures

We maintain disclosure

controls and procedures

designed to ensure information required

to be disclosed in

reports we file or submit under the Securities Exchange

Act of 1934, as amended (the Act), is recorded, processed,

summarized and reported within the

time periods specified in Securities and Exchange Commission rules

and

forms, and that such information

is accumulated and communicated

to management, including our principal

executive and principal financial officers,

as appropriate, to allow timely decisions

regarding required disclosure.

As of December 31, 2021, with the participation of our management,

our Chairman and Chief Executive Officer

(principal executive officer) and

our Executive Vice President and

Chief Financial Officer (principal financial officer)

carried out an evaluation, pursuant

to Rule 13a-15(b) of the Act, of ConocoPhillips' disclosure controls

and

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

Based upon that evaluation, our Chairman and

Chief

Executive Officer and our Executive

Vice President and Chief Financial Officer concluded

our disclosure controls

and procedures were operating

effectively as of December 31, 2021.

There have been no changes in our internal

control over financial reporting, as defined in

Rule 13a-15(f) of the Act,

in the period covered by this report that

have materially affected,

or are reasonably likely to

materially affect, our

internal control over financial

reporting.

Management's Annual Report

on Internal Control Over Financial Reporting

This report is included in Item 8 on page

75

and is incorporated herein by

reference.

Report of Independent Registered

Public Accounting Firm

This report is included in Item 8 on page 76 and is incorporated

herein by reference.

Item 9B.

Other Information

None.

Item 9C.

Disclosure Regarding Foreign Jurisdictions that Prevent

Inspections

Not applicable.

179

ConocoPhillips

2021 10-K

Part III

Item 10.

Directors, Executive Officers

and Corporate Governance

Information regarding

our executive officers

appears in Part I of this report on page

Code of Business Ethics and Conduct for Directors

and Employees

We have a Code of Business Ethics

and Conduct for Directors and Employees

(Code of Ethics), including our

principal executive officer,

principal financial officer,

principal accounting officer and persons

performing similar

functions.

We have posted

a copy of our Code of Ethics on the "Corporate

Governance" section of our internet

website at

www.conocophillips.com

(within the Investors>Corporate

Governance section)

Any waivers of the

Code of Ethics must be approved, in advance,

by our full Board of Directors.

Any amendments to, or waivers

from,

the Code of Ethics that apply to our executive

officers and directors

will be posted on the "Corporate Governance"

section of our internet website.

All other information required

by Item 10 of Part III will be included in our Proxy

Statement relating to our 2022

Annual Meeting of Stockholders, to be filed pursuant

to Regulation 14A on or before April

30, 2022, and is

incorporated herein by

reference.*

Item 11.

Executive Compensation

Information required by Item

11 of Part III will be included in our Proxy

Statement relating to our 2022 Annual

Meeting of Stockholders, to be filed pursuant

to Regulation 14A on or before

April 30, 2022, and is incorporated

herein by reference.*

Item 12.

Security Ownership of Certain Beneficial Owners and Management and

Related Stockholder Matters

Information required by Item

12 of Part III will be included in our Proxy

Statement relating to our 2022 Annual

Meeting of Stockholders, to be filed pursuant

to Regulation 14A on or before

April 30, 2022, and is incorporated

herein by reference.*

Item 13.

Certain Relationships and Related Transactions,

and Director

Independence

Information required by Item

13 of Part III will be included in our Proxy

Statement relating to our 2022 Annual

Meeting of Stockholders, to be filed pursuant

to Regulation 14A on or before

April 30, 2022, and is incorporated

herein by reference.*

Item 14.

Principal Accounting Fees and Services

Information required by Item

14 of Part III will be included in our Proxy

Statement relating to our 2022 Annual

Meeting of Stockholders, to be filed pursuant

to Regulation 14A on or before

April 30, 2022, and is incorporated

herein by reference.*

---

*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing

in our 2022 Proxy

Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a

part of this report.

ConocoPhillips

2021 10-K

180

Part IV

Item 15.

Exhibits, Financial Statement Schedules

(a)

Financial Statements and Supplementary

Data

The financial statements and supplementary

information listed in the Index

to Financial Statements,

which appears on page

74

, are filed as part of this annual report.

Financial Statement Schedules

All financial statement schedules

are omitted because they are

not required, not significant, not

applicable or the information is shown

in another schedule, the financial statements

or the notes to

consolidated financial statements.

Exhibits

The exhibits listed in the Index to

Exhibits, which appears on pages

181

through 185, are filed as part of

this annual report.

181

ConocoPhillips

2021 10-K

ConocoPhillips

Index to Exhibits

Incorporated by Reference

Exhibit

No.

Description

Exhibit

Form

File No.

2.1

Separation and Distribution Agreement Between ConocoPhillips and Phillips

66, dated April 26, 2012.

2.1

8-K

001-32395

2.2†‡

Purchase and Sale Agreement, dated March 29, 2017, by and among

ConocoPhillips Company, ConocoPhillips Canada Resources Corp.,

ConocoPhillips Canada Energy Partnership, ConocoPhillips Western Canada

Partnership, ConocoPhillips Canada (BRC) Partnership, ConocoPhillips Canada

E&P ULC, and Cenovus Energy Inc.

2.1

10-Q

001-32395

2.3†‡

Asset Purchase and Sale Agreement Amending Agreement, dated as of May

16, 2017, by and among ConocoPhillips Company, ConocoPhillips Canada

Resources Corp., ConocoPhillips Canada Energy Partnership, ConocoPhillips

Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership,

ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc.

2.2

8-K

001-32395

2.4

Agreement and Plan of Merger, dated as of October 18, 2020, among

ConocoPhillips, Falcon Merger Sub Corp. and Concho Resources Inc.

2.1

8-K

001-32395

3.1

Amended and Restated Certificate of Incorporation.

3.1

10-Q

001-32395

3.2

Certificate of Designations of Series A Junior Participating Preferred Stock of

ConocoPhillips.

3.2

8-K

000-49987

3.3

Amended and Restated By-Laws of ConocoPhillips, as amended and restated

as of October 9, 2015.

3.1

8-K

001-32395

3.4*

Restated Certificate of Incorporation of ConocoPhillips Company, dated

February 6, 2019.

ConocoPhillips and its subsidiaries are parties to

several debt instruments

under which the total amount of securities authorized

does not exceed

10 percent of the total assets of ConocoPhillips

and its subsidiaries on a

consolidated basis.

Pursuant to paragraph

4(iii)(A) of Item 601(b) of

Regulation S-K, ConocoPhillips

agrees to furnish a copy of such instruments

to

the SEC upon request.

4.1

Description of Securities of the Registrant.

4.1

10-K

001-32395

10.1

1986 Stock Plan of Phillips Petroleum Company.

10.11

10-K

004-49987

10.2

1990 Stock Plan of Phillips Petroleum Company.

10.12

10-K

004-49987

10.5

Amendment and Restatement of ConocoPhillips Supplemental Executive

Retirement Plan, dated April 19, 2012.

10.14

10-Q

001-32395

10.7

Omnibus Securities Plan of Phillips Petroleum Company.

10.19

10-K

004-49987

10.10.1

Amended and Restated ConocoPhillips Key Employee Supplemental

Retirement Plan, dated January 1, 2020.

10.10.1

10-K

001-32395

10.10.2

Eighth Amendment to Retirement Plans as amended and restated effective

January 1, 2016.

10.1

10-Q

001-32395

ConocoPhillips

2021 10-K

182

10.11.1

Amended and Restated Defined Contribution Make-Up Plan of

ConocoPhillips-Title I, dated January 1, 2020.

10.11.1

10-K

001-32395

10.11.2

Amended and Restated Defined Contribution Make-Up Plan of

ConocoPhillips-Title II, dated January 1, 2020.

10.11.2

10-K

001-32395

10.12

2002 Omnibus Securities Plan of Phillips Petroleum Company.

10.26

10-K

000-49987

10.15

Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips.

10.17

10-K

001-32395

10.16.1

Rabbi Trust Agreement dated December 17, 1999.

10.11

10-K

001-14521

10.16.2

Amendment to Rabbi Trust Agreement dated February 25, 2002.

10.39.1

10-K

000-49987

10.16.3

Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998.

10.17.3

10-K

001-32395

10.16.4

First Amendment to the Trust Agreement under the Phillips Petroleum

Company Grantor Trust Agreement, dated May 3, 1999.

10.17.4

10-K

001-32395

10.16.5

Second Amendment to the Trust Agreement under the Phillips Petroleum

Company Grantor Trust Agreement, dated January 15, 2002.

10.17.5

10-K

001-32395

10.16.6

Third Amendment to the Trust Agreement under the Phillips Petroleum

Company Grantor Trust Agreement, dated October 5, 2006.

10.17.6

10-K

001-32395

10.16.7

Fourth Amendment to the Trust Agreement under the

ConocoPhillips Company Grantor Trust Agreement, dated May 1, 2012.

10.17.7

10-K

001-32395

10.16.8

Fifth Amendment to the Trust Agreement under the ConocoPhillips Company

Grantor Trust Agreement, dated May 20, 2015.

10.17.8

10-K

001-32395

10.17.1

ConocoPhillips Directors' Charitable Gift Program.

10.40

10-K

000-49987

10.17.2

First and Second Amendments to the ConocoPhillips Directors' Charitable Gift

Program.

10

10-Q

001-32395

10.19.1

Amended and Restated Key Employee Deferred Compensation Plan of

ConocoPhillips-Title I, dated January 1, 2020.

10.19.1

10-K

001-32395

10.19.2

Amended and Restated Key Employee Deferred Compensation Plan of

ConocoPhillips-Title II, dated January 1, 2020.

10.19.2

10-K

001-32395

10.20

Amendment and Restatement of ConocoPhillips Key Employee Change in

Control Severance Plan, effective January 1, 2014.

10.21

10-K

001-32395

10.20.1*

Amendment and Restatement of ConocoPhillips Key Employee Change in

Control Severance Plan, effective December 2, 2021.

10.22.1

2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

Schedule

14A

Proxy

000-49987

10.22.2

Form of Stock Option Award Agreement under the Stock Option and Stock

Appreciation Rights Program under the 2004 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips.

10.26

10-K

001-32395

10.22.3

Form of Performance Share Unit Award Agreement under the Performance

Share Program under the 2004 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips.

10.27

10-K

001-32395

10.23

Omnibus Amendments to certain ConocoPhillips employee benefit plans,

adopted December 7, 2007.

10.30

10-K

001-32395

183

ConocoPhillips

2021 10-K

10.24

2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

Schedule

14A

Proxy

001-32395

10.25.1

2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

Schedule

14A

Proxy

001-32395

10.25.2

Form of Stock Option Award Agreement under the Stock Option and Stock

Appreciation Rights Program under the 2011 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips, effective February 9, 2012.

10

10-Q

001-32395

10.25.4

Form of Performance Share Unit Agreement under the Restricted Stock

Program under the 2011 Omnibus Stock and Performance Incentive Plan of

ConocoPhillips, dated February 5, 2013.

10.26.6

10-K

001-32395

10.25.7

Form of Stock Option Award Agreement under the Stock Option and Stock

Appreciation Rights Program under the 2011 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips, dated February 5, 2013.

10.26.9

10-K

001-32395

10.25.8

Form of Make-Up Grant Award Agreement under the 2011 Omnibus Stock and

Performance Incentive Plan of ConocoPhillips, dated January 1, 2012.

10.2

10-Q

001-32395

10.25.9

Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock

Option Program granted under the 2011 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.1

10-Q

001-32395

10.25.10

Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock

Option Program granted under the 2014 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips, dated February 16, 2016.

10.26.12

10-K

001-32395

10.25.12

Form of Performance Period IX Award Agreement, as part of the

ConocoPhillips Performance Share Program granted under the 2011 Omnibus

Stock and Performance Incentive Plan of ConocoPhillips, dated February 18,

10.3

10-Q

001-32395

10.25.14

Form of Performance Period X Award Agreement, as part of the

ConocoPhillips Performance Share Program granted under the 2011 Omnibus

Stock and Performance Incentive Plan of ConocoPhillips, dated February 18,

10.5

10-Q

001-32395

10.25.17

Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock

and Performance Incentive Plan of ConocoPhillips, dated March 31, 2014.

10.11

10-Q

001-32395

10.25.18

Form of Performance Share Unit Award Terms and Conditions for

Performance Period 18, as part of the ConocoPhillips Performance Share

Program granted under the 2014 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips, dated February 13, 2018.

10.26.24

10-K

001-32395

10.26.1

2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

10.1

8-K

001-32395

10.26.4

Form of Non-Employee Director Restricted Stock Units Terms and Conditions,

as part of the Deferred Compensation Plan for Non-Employee Directors of

ConocoPhillips, dated January 15, 2016.

10.3

10-Q

001-32395

10.26.7

Form of Key Employee Award Terms and Conditions, as part of the

ConocoPhillips Stock Option Program granted under the 2014 Omnibus Stock

and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.

10.1

10-Q

001-32395

ConocoPhillips

2021 10-K

184

10.26.11

Form of Key Employee Award Terms and Conditions as part of the

ConocoPhillips Executive Restricted Stock Unit Program granted under the

2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated

February 13, 2018.

10.27.12

10-K

001-32395

10.26.13

Form of Key Employee Award Terms and Conditions as part of the

ConocoPhillips Restricted Stock Program granted under the 2014 Omnibus

Stock and Performance Incentive Plan of ConocoPhillips, dated February 13,

10.27.14

10-K

001-32395

10.26.14

Form of Retention Award Terms and Conditions, 2017 revision, as part of the

Restricted Stock Unit Award, granted under the 2014 Omnibus Stock and

Performance Incentive Plan of ConocoPhillips.

10.27.15

10-K

001-32395

10.26.15

Form of Key Employee Award Terms and Conditions as part of the

ConocoPhillips Restricted Stock Unit Program granted under the 2014

Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated

February 14, 2019.

10.27.16

10-K

001-32395

10.27

Amended and Restated 409A Annex to Nonqualified Deferred Compensation

Arrangements of ConocoPhillips, dated January 1, 2020.

10.27

10-K

001-32395

10.29

Amendment and Restatement of the Burlington Resources Inc. Management

Supplemental Benefits Plan, dated April 19, 2012.

10.9

10-Q

001-32395

10.30.1

Successor Trustee Agreement of the Deferred Compensation Trust Agreement

for Non-Employee Directors of ConocoPhillips dated July 31, 2020.

10.1

10-Q

001-32395

10.30.2

First Amendment to the Successor Trust Agreement of the Deferred

Compensation Trust Agreement for Non-Employee Directors of

ConocoPhillips, dated August 4, 2020.

10.2

10-Q

001-32395

10.31

Indemnification and Release Agreement between ConocoPhillips and Phillips

66, dated April 26, 2012.

10.1

8-K

001-32395

10.32

Intellectual Property Assignment and License Agreement between

ConocoPhillips and Phillips 66, dated April 26, 2012.

10.2

8-K

001-32395

10.33

Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April

26, 2012.

10.3

8-K

001-32395

10.34

Employee Matters Agreement between ConocoPhillips and Phillips 66, dated

April 12, 2012.

10.4

8-K

001-32395

10.36

ConocoPhillips Clawback Policy dated October 3, 2012.

10.3

10-Q

001-32395

10.37

Term Loan Agreement, between ConocoPhillips, as borrower, ConocoPhillips

Company, as guarantor, Toronto Dominion (Texas) LLC, as administrative

agent and the banks party thereto, with TD Securities (USA) LLC, as lead

arranger and bookrunner, dated March 18, 2016.

10.1

8-K

001-32395

10.38

Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated

December 28, 2018.

10.39

10-K

001-32395

10.40

Form of Key Employee Award Terms and Conditions, as part of the

ConocoPhillips Targeted Variable Long Term Incentive Program, granted under

the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,

dated September 23, 2019.

10.1

10-Q

001-32395

10.41

ConocoPhillips Executive Restricted Stock Unit Program, dated February 11,

10.1

10-Q

001-32395

185

ConocoPhillips

2021 10-K

10.42

Form of Retention Award Terms and Conditions, as part of the Restricted

Stock Unit Award, granted under the 2014 Omnibus Stock and Performance

Incentive Plan of ConocoPhillips.

10.1

10-Q

001-32395

10.43

Form of Inducement Grant Award Agreement under the 2014 Omnibus Stock

and Performance Incentive Plan of ConocoPhillips, dated January 15, 2021.

10.3

10-Q

001-32395

10.44

Compensation Resolutions regarding Matthew J. Fox, dated April 8, 2021.

10.1

10-Q

001-32395

10.45

Form of Aircraft Time Sharing Agreement by and between certain executives

and ConocoPhillips dated June 21, 2021.

10.2

10-Q

001-32395

10.46

Purchase and Sale Agreement, dated as of September 20, 2021, by and

between Shell Enterprises LLC and ConocoPhillips.

10.1

10-Q

001-32395

10.47*

Amendment and Restatement of ConocoPhillips Executive Severance Plan,

dated December 2, 2021.

21*

List of Subsidiaries of ConocoPhillips.

22*

Subsidiary Guarantors of Guaranteed Securities.

23.1*

Consent of Ernst & Young LLP.

23.2*

Consent of DeGolyer and MacNaughton.

31.1*

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

Securities Exchange Act of 1934.

31.2*

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

Securities Exchange Act of 1934.

32*

Certifications pursuant to 18 U.S.C. Section 1350.

99*

Report of DeGolyer and MacNaughton.

101.INS*

Inline XBRL Instance Document.

101.SCH*

Inline XBRL Schema Document.

101.CAL*

Inline XBRL Calculation Linkbase Document.

101.DEF*

Inline XBRL Definition Linkbase Document.

101.LAB*

Inline XBRL Labels Linkbase Document.

101.PRE*

Inline XBRL Presentation Linkbase Document.

104*

Cover Page Interactive

Data File (formatted

as Inline XBRL and contained in

Exhibit 101).

Filed herewith.

†

The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K.

ConocoPhillips agrees to furnish

a copy of any schedule omitted from this exhibit to the SEC upon request.

‡ ConocoPhillips has previously been granted confidential treatment for certain portions

of this exhibit pursuant to Rule 24b-2

under the Securities Exchange Act of 1934, as amended.

ConocoPhillips

2021 10-K

186

Signature

Pursuant to the requirements

of Section 13 or 15(d) of the Securities Exchange Act of 1934,

the registrant has duly

caused this report to be signed on its behalf by the

undersigned, thereunto duly authorized.

CONOCOPHILLIPS

February 17, 2022

/s/ Ryan M. Lance

Ryan M. Lance

Chairman of the Board of Directors

and Chief Executive Officer

Pursuant to the requirements

of the Securities Exchange Act of 1934, this report

has been signed, as of February

17, 2022, on behalf of the registrant

by the following officers in the capacity

indicated and by a majority of

directors.

Signature

Title

/s/ Ryan M. Lance

Chairman of the Board of Directors

Ryan M. Lance

and Chief Executive Officer

(Principal executive officer)

/s/ William L. Bullock, Jr.

Executive Vice President and

William L. Bullock, Jr.

Chief Financial Officer

(Principal financial officer)

/s/ Kontessa S. Haynes-Welsh

Chief Accounting Officer

Kontessa S. Haynes-Welsh

(Principal accounting officer)

187

ConocoPhillips

2021 10-K

/s/ Charles E. Bunch

Director

Charles E. Bunch

/s/ Caroline M. Devine

Director

Caroline M. Devine

/s/ Gay Huey Evans

Director

Gay Huey Evans

/s/ John V.

Faraci

Director

John V.

Faraci

/s/ Jody Freeman

Director

Jody Freeman

/s/ Jeffrey A. Joerres

Director

Jeffrey A. Joerres

/s/ Timothy A. Leach

Director

Timothy A. Leach

/s/ William H. McRaven

Director

William H. McRaven

/s/ Sharmila Mulligan

Director

Sharmila Mulligan

/s/ Eric D. Mullins

Director

Eric D. Mullins

/s/ Arjun N. Murti

Director

Arjun N. Murti

/s/ Robert A. Niblock

Director

Robert A. Niblock

/s/ David T.

Seaton

Director

David T.

Seaton

/s/ R.A. Walker

Director

R.A. Walker