SEC EDGAR Filing

Company: CONOCOPHILLIPS
CIK: 1163165
Filing Type: 10-K
Filing Date: 2020-02-18
Period of Report: 2019-12-31
SIC Code: 2911
State of Incorporation: DE
State of Location: TX
Fiscal Year End: 1231

Filename: 1163165_10K_2019_0001193125-20-039954.htm
Filing Index: https://www.sec.gov/Archives/edgar/data/1163165/0001193125-20-039954-index.html
HTM Filing Link: https://www.sec.gov/Archives/edgar/data/1163165/000119312520039954/d875559d10k.htm
Complete Text Filing Link: https://www.sec.gov/Archives/edgar/data/1163165/0001193125-20-039954.txt

---

Item 1. Business

Item 1A. Risk Factors
Item 1A. RISK FACTORS
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 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.
Our operating results, our future rate of growth
and the carrying value of our assets are exposed
to the
effects of changing commodity prices.
Prices for crude oil, bitumen, natural gas, NGLs and
LNG can fluctuate widely.
Brent crude oil prices
averaged $64 per barrel in 2019, ranging from
a low of $53 per barrel in January to a high of almost
$75 per
barrel in April.
Given volatility in commodity price drivers
and the worldwide political and economic
environment generally, as well as increased uncertainty generated by recent (and
potential future) armed
hostilities in various oil-producing regions around the
globe, price trends may continue to be volatile.
Our
revenues, operating results and future rate of growth
are highly dependent on the prices
we receive for our
crude oil, bitumen, natural gas, NGLs and
LNG.
The factors influencing these prices are
beyond our control.
Lower crude oil, bitumen, natural gas, NGL and
LNG prices may have a material adverse effect on our
revenues, operating income, cash flows and liquidity, and may also affect the amount
of dividends we elect to
declare and pay on our common stock 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, adversely affecting our proved reserves, reserve replacement
ratio and
accelerating the reduction in our existing reserve levels
as we continue production from upstream
fields.
Significant reductions in crude oil, bitumen, natural
gas, NGLs and LNG prices could also require
us to reduce
our capital expenditures, impair the carrying value
of our assets or discontinue the classification
of certain
assets as proved reserves.
In the past three years, we recognized several
impairments, which are described in
Note 9-Impairments and the “APLNG” section
of Note 6-Investments, Loans and Long-Term Receivables,
in the Notes to Consolidated Financial Statements.
If commodity prices remain low relative
to their historic
levels, and as we continue to optimize our investments
and exercise capital flexibility, it is reasonably likely
we will incur future impairments to long-lived assets
used in operations, investments in nonconsolidated
entities accounted for under the equity method and
unproved properties.
Although it is not reasonably
practicable to quantify the impact of any future
impairments at this time, our results of operations
could be
adversely affected as a result.
Our ability to declare and pay dividends and repurchase
shares is subject to certain considerations.
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.
●
Other factors our Board of Directors deems
relevant.
We expect to continue to pay quarterly dividends to our stockholders; however, our Board of Directors may
reduce our 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.
Additionally, as of December 31, 2019, $5.4 billion of repurchase authority
remained of the $15 billion share
repurchase program our Board of Directors had
authorized.
In February, 2020, our Board of Directors
approved an increase to our repurchase authorization
from $15 billion to $25 billion, to support
our plan for
future share repurchases.
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.
Any downward revision in the amount of dividends
we pay to stockholders or the number of shares
we
purchase under our share repurchase program could
have an adverse effect on the market price of our common
stock.
We may need additional capital in the future, and it may not be available on acceptable
terms.
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.
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.
In particular, in August 2018, we entered into a settlement
agreement with Petróleos de Venezuela, S.A.
(PDVSA) providing for the payment of approximately
$2 billion over a five-year period in connection
with an
arbitration award issued by the International
Chamber of Commerce (ICC) Tribunal in favor of ConocoPhillips
on a contractual dispute arising from Venezuela’s expropriation of our interests in the Petrozuata and Hamaca
heavy oil ventures and other pre-expropriation
fiscal measures.
We collected approximately $0.8 billion of the
$2.0 billion settlement in 2018 and 2019.
PDVSA has defaulted on its remaining payment
obligations under
this agreement, we are therefore now forced to
incur additional costs as we seek to recover any
unpaid amounts
under the agreement.
Unless we successfully add to our existing proved
reserves, our future crude oil, bitumen,
natural gas and
NGL production will decline, resulting in an
adverse impact to our business.
The rate of production from upstream fields
generally declines as reserves are depleted.
If we do not conduct
successful exploration and development activities,
or, through engineering studies, optimize production
performance or identify additional or secondary
recovery reserves, our proved reserves
will decline materially
as we produce crude oil, bitumen, natural gas and
NGLs, and our business will experience reduced cash
flows
and results of operations.
Any cash conservation efforts we may undertake as a result
of commodity price
declines may further limit our ability to replace
depleted reserves.
The exploration and production of oil and gas
is a highly competitive 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 oil, bitumen,
natural gas and
NGLs in an efficient, cost-effective manner.
Some of our competitors are larger and have greater
resources
than we do or may be willing to incur a higher
level of risk than we are willing to incur to obtain
potential
sources of supply.
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.
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 in the U.S. and in other
countries in
which we operate.
For a description of the most significant of these
environmental laws and regulations, see
the “Contingencies-Environmental” section
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.The
discharge of pollutants into the environment.
●
Emissions into the atmosphere, such as nitrogen
oxides, sulfur dioxide, mercury and GHG emissions.
●
Carbon taxes.
●
The handling, use, storage, transportation, disposal
and cleanup of hazardous materials and hazardous
and nonhazardous wastes.
●
The dismantlement, abandonment and restoration
of our properties and facilities at the
end of their
useful lives.
●
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.
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
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 initiatives
relating to global climate change, such as limitations
on GHG emissions, may impact or limit
our business plans, result in significant expenditures,
promote
alternative uses of energy or reduce demand
for our products.
Continuing political and social attention to the
issue of global climate change has resulted in
both existing and
pending international agreements and national,
regional or local legislation and regulatory
measures to limit
GHG emissions, such as cap and trade regimes, carbon
taxes, restrictive permitting, increased fuel efficiency
standards and incentives or mandates for renewable
energy.
For example, in December 2015, the U.S. joined
the international community at the 21st Conference
of the Parties of the United Nations Framework
Convention on Climate Change in Paris that
prepared an agreement requiring member countries
to review and
represent a progression in their intended GHG
emission reduction goals every five years
beginning in 2020.
While the U.S. announced its intention to withdraw
from the Paris Agreement, there is no guarantee
that the
commitments made by the U.S. will not be implemented,
in whole or in part, by U.S. state and local
governments or by major corporations headquartered
in the U.S.
In addition, our operations continue in
countries around the world which are party to,
and have not announced an intent to
withdraw from, the Paris
Agreement.
The implementation of current agreements and
regulatory measures, as well as any future
agreements or measures addressing climate
change and GHG emissions, may adversely
impact the demand for
our products, impose taxes on our products or operations
or require us to purchase emission credits
or reduce
emission of GHGs from our operations.
As a result, we may experience declines in commodity
prices or incur
substantial capital expenditures and compliance,
operating, maintenance and remediation costs,
any of which
may have an adverse effect on our business and results
of operations.
Additionally, increasing attention to global climate change has resulted in pressure
upon shareholders,
financial institutions and/or financial markets
to modify their relationships with oil and gas companies
and to
limit investments and/or funding to such companies,
which could increase our costs or otherwise
adversely
affect our business and results of operations.
Furthermore, increasing attention to global climate
change has resulted in an increased likelihood of
governmental investigations and private litigation,
which could increase our costs or otherwise adversely
affect
our business.
In 2017 and 2018, cities, counties, and
a state government in California, New
York, Washington,
Rhode Island and Maryland, as well as the Pacific
Coast Federation of Fishermen’s Association, Inc., filed
lawsuits against oil and gas companies, including
ConocoPhillips, seeking compensatory damages
and
equitable relief to abate alleged climate change impacts.
ConocoPhillips is vigorously defending against
these
lawsuits.
The ultimate outcome and impact to us
cannot be predicted with certainty, and we could incur
substantial legal costs associated with defending
these and similar lawsuits in the future.
In addition, although
we design and operate our business operations
to accommodate expected climatic
conditions, to the extent there are significant
changes in the earth’s climate, such as more severe or frequent
weather conditions in the markets where we operate
or the areas where our assets reside, we could incur
increased expenses, our operations could be adversely
impacted, and demand for our products could
fall.
For more information on legislation or precursors
for possible regulation relating to global climate
change that
affect or could affect our operations and a description of the company’s response, see the
“Contingencies-
Climate Change” section of Management’s Discussion and Analysis
of Financial Condition and Results of
Operations.
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, governments have imposed
or proposed restrictions on our operations;
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.
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 for many decades,
a number of new laws, regulations and permitting
requirements are under consideration by the
U.S. EPA and others which could result in increased costs,
operating restrictions, operational delays or limit
the ability to develop oil and natural gas resources.
Certain
jurisdictions in which we operate, including state
and local governments in Colorado, 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.
For example, in 2018, Colorado voters rejected
Proposition 112, a Colorado ballot initiative that
would have drastically limited the use of hydraulic
fracturing in Colorado.
In the event that ballot initiatives,
local or state 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.
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 regulations
may affect our ability to collect payments such
as those pertaining to the settlement with PDVSA
or the ICSID Award against the Government of Venezuela;
or to obtain or maintain permits, including those
necessary for drilling and development of wells
in various
locations.
Local political and economic factors in international
markets could have a material adverse effect on us.
Approximately 50 percent of our hydrocarbon
production was derived from production outside
the U.S. in
2019, and 39 percent of our proved reserves, as
of December 31, 2019, were located outside
the U.S.
We are
subject to risks associated with operations in 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 effect of international trade discussion and disputes),
changing political conditions and international
monetary and currency rate fluctuations.
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.
Our business may be adversely affected by price controls,
government-imposed limitations on production
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 above, 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.
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.
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.
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.
We may not be able to successfully complete any disposition we elect to pursue.
From time to time, we may seek to divest portions
of our business or investments that
are not important to our
ongoing strategic objectives.
Any dispositions we undertake may involve numerous
risks and uncertainties,
any of which could adversely affect our results of operations
or financial condition.
In particular, we may not
be able to successfully complete any disposition
on a timeline or on terms acceptable
to us, if at all, whether
due to market conditions, regulatory challenges
or other concerns.
In addition, the reinvestment of capital
from disposition proceeds may not ultimately
yield investment returns in line with our internal
or external
expectations.
Any dispositions we pursue may also result in
disruption to other parts of our business,
including through the diversion of resources
and management attention from our ongoing
business and other
strategic matters, or through the disruption
of relationships with our employees and key
vendors.
Further, in
connection with any disposition, we may enter into
transition services agreements or undertake
indemnity or
other obligations that may result in additional
expenses for us.
We may also be required under applicable
accounting rules to recognize impairments
associated with any disposition we pursue,
whether or not
completed.
As part of our disposition strategy, on May 17, 2017, we completed the sale of
our 50 percent nonoperated
interest in the FCCL Partnership, as well as the
majority of our western Canada gas assets
to Cenovus Energy.
Consideration for the transaction included 208
million Cenovus Energy common shares.
We may not be able
to liquidate the shares issued to us by Cenovus
Energy at prices we deem acceptable, or at all.
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,
crude oil spills, severe weather, geological events, labor disputes,
armed hostilities, terrorist attacks, sabotage, civil
unrest or cyber attacks.
Our operations may also be
adversely affected by unavailability, interruptions or accidents involving services
or infrastructure required to
develop, produce, process or transport our production,
such as contract labor, drilling rigs, pipelines, railcars,
tankers, barges or other infrastructure.
Our operations are subject to the additional hazards
of pollution,
releases of toxic gas 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.
Further, 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.
Our technologies, systems and networks may be subject
to cyber attacks.
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 cyber security
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)
corrupted or unusable, threats to the security
of our facilities and infrastructure as well
as those of third parties
with whom we do business 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 cyber breach of these
operating systems, or of the networks 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 or make it difficult or impossible to accurately
account for production and settle transactions.
Although we have experienced occasional breaches
of our cyber security, none of these breaches have had a
material effect on our business, operations or reputation.
As cyber attacks continue to evolve, 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 various 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 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, significant litigation exposure and legal
liability or regulatory fines, penalties or intervention.
Any of these could materially and adversely affect our
business, results of operations or financial condition.
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 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.

Item 1B. Unresolved Staff Comments
Item 1B. UNRESOLVED STAFF COMMENTS
None.

Item 2. Properties

Item 3. Legal Proceedings
Item 3.
LEGAL PROCEEDINGS
The following is a description of reportable legal
proceedings, including those involving governmental
authorities under federal, state and local laws regulating
the discharge of materials into the environment
for
this reporting period.
The following proceedings include those
matters that arose during the fourth quarter of
2019, as well as matters previously reported in our
2018 Form 10-K and our first-, second- and third-quarter
2019 Form 10-Qs that were not resolved prior
to the fourth quarter of 2019.
Material developments to the
previously reported matters have been included
in the descriptions below.
While it is not possible to
accurately predict the final outcome of these pending
proceedings, if any one or more of such proceedings
were to be decided adversely to ConocoPhillips,
we expect there would be no material effect on our
consolidated financial position.
Nevertheless, such proceedings are reported pursuant
to SEC regulations.
On April 30, 2012, the separation of our downstream
business was completed, creating two independent
energy companies: ConocoPhillips and Phillips
66.
In connection with the separation, we entered
into an
Indemnification and Release Agreement, which
provides for cross-indemnities between Phillips
66 and us and
established procedures for handling claims subject
to indemnification and related matters, such
as legal
proceedings.
We have included matters where we remain or have subsequently become
a party to a
proceeding relating to Phillips 66, in accordance
with SEC regulations.
We do not expect any of those matters
to result in a net claim against us.
Matters Previously Reported-Phillips 66
In May 2012, the Illinois Attorney General's
office filed and notified ConocoPhillips of a complaint with
respect to operations at the Phillips 66 WRB
Wood River Refinery alleging violations of the Illinois
groundwater standards and a third-party's
hazardous waste permit.
The complaint seeks remediation of area
groundwater; compliance with the hazardous waste
permit; enhanced pipeline and tank integrity measures;
additional spill reporting; and yet-to-be specified
amounts for fines and penalties.
Matters Previously Reported-ConocoPhillips
On June 28, 2018, the Texas Commission on Environmental Quality issued a Proposed
Agreed Order to
ConocoPhillips Company to resolve alleged violations
of the Texas Health & Safety Code and/or Commission
Rules occurring in 2015 through 2017 at a formerly
owned gas injection plant in Howard
County, Texas.
In
November of 2019, the company concluded
this matter by entering into an Agreed Order
with the agency and
paying an administrative penalty of $120,014.

Item 4. Mine Safety Disclosures
Item 4.
MINE SAFETY DISCLOSURES
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Name
Position Held
Age*
Catherine A. Brooks
Vice President and Controller
William L. Bullock, Jr.
President, Asia Pacific & Middle East
Ellen R. DeSanctis
Senior Vice President, Corporate Relations
Matt J. Fox
Executive Vice President and Chief Operating Officer
Michael D. Hatfield
President, Alaska, Canada and Europe
Ryan M. Lance
Chairman of the Board of Directors and Chief Executive
Officer
Andrew D. Lundquist
Senior Vice President, Government Affairs
Dominic E. Macklon
President, Lower 48
Kelly B. Rose
Senior Vice President, Legal, General Counsel and Corporate Secretary
Don E. Wallette, Jr.
Executive Vice President and Chief Financial Officer
*On February 15, 2020.
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 12, 2020.
Set forth below is information about the executive
officers.
Catherine A. Brooks
was appointed Vice President and Controller as of January 1, 2019, having
previously
served as General Auditor since August 2018.
Prior to serving as General Auditor, she was Assistant
Controller from February 2016 to August 2018.
She became Manager, Finance & Performance Analysis in
April 2014 and served in that role until February
2016.
Ms. Brooks previously held the position
of Manager,
External Reporting from May 2010 to April
2014.
William L. Bullock, Jr.
was appointed President, Asia Pacific & Middle
East as of April 1, 2015, having
previously served as Vice President, Corporate Planning & Development
since May 2012.
Ellen R. DeSanctis
was appointed Senior Vice President, Corporate Relations as of January 1,
2019, having
previously served as Vice President, Investor Relations and Communications
since May 2012.
Prior to that,
she was employed by Petrohawk Energy Corp. where she
served as Senior Vice President, Corporate
Communications since 2010.
Matt J. Fox
was appointed Executive Vice President and Chief Operating Officer as of January 1,
2019,
having previously served as Executive Vice President, Strategy, Exploration and Technology since April 2016
and Executive Vice President, Exploration and Production, from 2012 to
2016.
Prior to that, he was employed
by Nexen, Inc., where he served as Executive
Vice President, International since 2010.
Michael D. Hatfield
was appointed President, Alaska, Canada and Europe
as of June 3, 2018, having
previously served as President, Canada since
October 2016.
Prior to that, he served as Vice President, Health,
Safety and Environment from December 2015
to October 2016.
Mr. Hatfield became Vice President, Cost
Optimization in March 2015 and served in that
role until December 2015.
Mr. Hatfield previously held the
position of Vice President, Rockies Business Unit from March 2013 to March
2015.
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
2009.
Andrew D. Lundquist
was appointed Senior Vice President,
Government Affairs in 2013.
Prior to that, he
served as managing partner of BlueWater Strategies LLC, since 2002.
Dominic E. Macklon
was appointed President, Lower 48 as of June
1, 2018, having previously served as Vice
President, Corporate Planning & Development since
January 2017.
Prior to that, he served as President, U.K.
from September 2015 to January 2017.
Mr. Macklon previously served as Senior Vice President, Oil Sands
from July 2012 to September 2015.
Kelly B. Rose
was appointed Senior Vice President, Legal, General Counsel and Corporate
Secretary in
September 2018.
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.
Don E. Wallette, Jr.
was appointed Executive Vice President and Chief Financial Officer on January
1, 2019,
having previously served as Executive Vice President, Finance, Commercial
and Chief Financial Officer since
April 2016 and as Executive Vice President, Commercial, Business Development
and Corporate Planning
from 2012 to 2016.
Prior to that, he served as President, Asia Pacific
from 2010 to 2012 and President,
Russia/Caspian from 2006 to 2010.
PART
II

Item 5. Market for Registrant's Common Equity
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
First
$
0.305
0.285
Second
0.305
0.285
Third
0.305
0.285
Fourth
0.420
0.305
Number of Stockholders of Record at January
31, 2020*
41,821
*In determining the number of stockholders, we consider clearing
agencies and security position listings as one stockholder for each
agency
listing.
The declaration of dividends is subject to the discretion
of our Board of Directors, and may be affected by
various factors, including our future earnings,
financial condition, capital requirements,
levels of indebtedness,
credit ratings and other considerations our Board of
Directors deems relevant.
Our Board of Directors has
adopted a quarterly dividend declaration policy providing
that the declaration of any dividends will be
determined quarterly by the Board of Directors
taking into account such factors as our
business model,
prevailing business conditions and our financial
results and capital requirements, without a predetermined
annual net income payout ratio.
On February 1, 2018, we announced that our Board
of Directors approved an increase in the
quarterly dividend
to $0.285 per share, compared with the previous
quarterly dividend of $0.265 per share.
On October 5, 2018, we announced that our Board
of Directors approved an increase in the
quarterly dividend
to $0.305 per share, compared with the previous
quarterly dividend of $0.285 per share.
On October 7, 2019, we announced that our Board
of Directors approved an increase in the quarterly
dividend
to $0.42 per share, compared with the previous
quarterly dividend of $0.305 per share.
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, 2019
4,844,970
$
55.54
4,844,970
$
5,855
November 1-30, 2019
4,020,276
58.20
4,020,276
5,621
December 1-31, 2019
3,943,490
62.31
3,943,490
5,375
12,808,736
$
58.46
12,808,736
*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.
In late 2016, we initiated our current share repurchase
program.
As of December 31, 2019, we had announced
a total authorization to repurchase $15 billion
of our common stock.
We repurchased $3 billion in 2017, $3
billion in 2018 and $3.5 billion in 2019.
Of the remaining authorization, we expect to
repurchase $3 billion in
2020.
In February 2020, we announced that the
Board of Directors approved an increase
to our repurchase
authorization from $15 billion to $25 billion,
to support our plan for future share repurchases.
Acquisitions for
the share repurchase program are made at management’s discretion,
at prevailing prices, subject to market
conditions and other factors.
Except as limited by applicable legal requirements,
repurchases may be
increased, decreased or discontinued at any time
without prior notice.
Shares of stock repurchased under the
plan are held as treasury shares.
See Risk Factors “Our ability to declare
and pay dividends and repurchase
shares is subject to certain considerations.”
Stock Performance Graph
The following graph shows the cumulative total
shareholder return (TSR) for ConocoPhillips’
common stock
in each of the five years from December 31, 2014,
to December 31, 2019.
The graph also compares the
cumulative total returns for the same five-year period
with the S&P 500 Index, the performance peer
group
used in the prior fiscal year (the “Prior Peer
Group”) and a new performance peer group for
the current fiscal
year (the “New Peer Group”).
The Prior Peer Group consists of BP, Chevron, ExxonMobil, Royal Dutch
Shell, Total, Apache, Devon, Marathon Oil Corporation and Occidental,
weighted according to the respective
peer’s stock market capitalization at the beginning
of each annual period.
For the purpose of aligning to
performance peers with similar complexities
and portfolios, the New Peer Group excludes
BP,
Royal Dutch
Shell, and Total, and includes Noble Energy, Hess, and EOG Resources.
For the 2018 Stock Performance
Graph, Anadarko was also presented within
the Prior Peer Group.
However, due to Anadarko’s acquisition by
Occidental completed in 2019, Anadarko’s performance has been excluded
from all five years of the Prior Peer
Group performance.
The comparison assumes $100 was invested
on December 31, 2014, in ConocoPhillips
stock, the S&P 500 Index and ConocoPhillips’
peer groups
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.
*Prior Peer Group: BP; Chevron; ExxonMobil; Royal Dutch Shell; Total; Apache; Devon, Marathon Oil Corporation; Occidental.
**New Peer Group: Chevron; ExxonMobil; Apache; Devon; EOG Resources; Hess; Marathon Oil Corporation;
Noble Energy; Occidental.

Item 6. Selected Financial Data
Item 6.
SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts
Sales and other operating revenues
$
32,567
36,417
29,106
23,693
29,564
Net income (loss)
7,257
6,305
(793)
(3,559)
(4,371)
Net income (loss) attributable to
ConocoPhillips
7,189
6,257
(855)
(3,615)
(4,428)
Per common share
Basic
6.43
5.36
(0.70)
(2.91)
(3.58)
Diluted
6.40
5.32
(0.70)
(2.91)
(3.58)
Total assets
70,514
69,980
73,362
89,772
97,484
Long-term debt
14,790
14,856
17,128
26,186
23,453
Cash dividends declared per common share
1.34
1.16
1.06
1.00
2.94
In 2019, we disposed of two ConocoPhillips U.K. subsidiaries
for proceeds of $2.2 billion after interest and
customary adjustments.
In 2017, we disposed of assets for consideration
of approximately $16 billion including
our 50 percent
nonoperated interest in the FCCL Partnership,
as well as the majority of our western Canada gas
assets, and
our interests in the San Juan Basin.
These factors
impact the comparability of historical
information.
See Management’s Discussion and Analysis of Financial Condition and
Results of Operations and the Notes to
Consolidated Financial Statements for a discussion
of factors that will enhance an understanding
of this data.

Item 7. Management's Discussion and Analysis
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,” “estimate,” “believe,”
“budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,”
“predict,” “seek,” “should,” “will,”
“would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,”
“outlook,” “effort,” “target”
and similar expressions identify forward-looking statements.
The company does not undertake to update,
revise or correct any of the forward-looking information unless required to do so under the federal securities
laws.
Readers are cautioned that such forward-looking statements should be read in conjunction with
the
company’s
disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE
‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,”
beginning on page
70.
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
BUSINESS ENVIRONMENT AND EXECUTIVE
OVERVIEW
ConocoPhillips is an independent E&P company
with operations and activities in 17 countries.
Our diverse,
low cost of supply portfolio includes resource-rich
unconventional plays in North America;
conventional
assets in North America, Europe, Asia and
Australia; LNG developments; oil sands in
Canada; and an
inventory of global conventional and unconventional
exploration prospects.
Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately
10,400 people worldwide and had total
assets of
$71 billion.
Overview
Global oil prices continued
to be volatile in 2019.
Optimism about worldwide economic growth during
the
first quarter turned to pessimism in the second quarter
as trade disputes dampened growth forecasts.
At the
end of the second quarter, geopolitical tensions in the Middle East,
threatening the safe passage of supertankers
carrying crude oil through the Persian Gulf, revived
oil prices.
Worldwide economic growth concerns returned
in the third quarter to depress prices, only to be
reversed again by geopolitical tensions in the
Middle East, as
oilfield infrastructure in Saudi Arabia was attacked,
temporarily disrupting approximately
five percent of the
world’s oil supply.
Production was restored relatively quickly, and prices settled in the fourth
quarter.
Brent
crude averaged $64
per barrel in 2019, down nine percent
from the prior year.
Our business strategy
anticipates prices will remain volatile and is designed
to be resilient in lower price environments, while
retaining upside during periods of higher prices.
Portfolio diversification and optimization, a strong
balance
sheet and disciplined capital investment have positioned
our company to navigate through volatile energy
cycles.
Our value proposition principles, namely, to focus on financial returns, maintain
a strong balance sheet, deliver
compelling returns of capital,
and expand cash flow through disciplined capital
investments, are being
executed in accordance with our priorities for
allocating cash flows from the business.
These priorities are:
invest capital to sustain
production and pay our existing dividend;
grow our existing dividend; maintain debt at
a level we believe is sufficient to maintain a strong investment
grade credit rating through price cycles; allocate
greater than 30 percent of our net cash provided
by operating activities to share repurchases
and dividends;
and, invest capital in a disciplined fashion to grow
our cash from operations.
We believe our commitment to
our value proposition, as evidenced by the results
discussed below, positions us for success in an environment
of price uncertainty and ongoing volatility.
In 2019, we successfully delivered on our priorities.
We achieved production growth of five percent on a total
BOE basis compared with the prior year, with higher value oil
volumes growing eight percent.
Cash provided
by operating activities of $11.1 billion exceeded capital expenditures
and
investments of $6.6 billion.
After
repurchasing $3.5 billion of our common stock
and paying $1.5 billion of dividends to shareholders,
we ended
the year with cash, cash equivalents and restricted
cash totaling $5.4 billion and $3.0 billion
of short-term
investments.
In October, we announced an increase to our quarterly dividend
of 38 percent to $0.42 per share
and announced planned 2020 share buybacks of
$3 billion.
In February 2020, we announced 2020 operating
plan capital of $6.5 billion to $6.7 billion.
The plan includes
funding for ongoing development drilling
programs, major projects, exploration and appraisal
activities, as
well as base maintenance.
Capital spend is expected to be higher in the first
quarter largely from winter
construction and exploration and appraisal drilling
in Alaska.
This guidance does not include capital for
acquisitions.
Key Operating and Financial Summary
Significant items
during 2019 included the following:
●
Net cash provided by operating activities was $11.1 billion and exceeded capital
expenditures and
investments of $6.6 billion.
●
Repurchased $3.5 billion of shares and paid $1.5 billion in dividends,
representing 45 percent of net cash
provided by operating activities.
●
Increased the quarterly dividend by 38 percent to $0.42 per share
.
●
Achieved 100 percent total reserve replacement and 117
percent organic replacement.
●
Underlying production, which excludes Libya and the net volume impact
from closed dispositions and
acquisitions of 51 MBOED in 2019 and 47 MBOED in 2018, grew 5 percent
.
●
Increased production from the Lower 48 Big 3 unconventionals-Eagle
Ford, Bakken and Permian
Unconventional-by 22 percent year-over-year.
●
Executed successful Alaska appraisal program; conducted appraisal drilling
and commissioned
infrastructure at Montney in Canada.
●
Completed Lower 48, Alaska and Argentina acquisitions;
awarded a 20-year extension of the Indonesia
Corridor Block PSC, with new terms.
●
Generated $3 billion in disposition proceeds; entered into agreements to
sell Australia-West
assets for $1.4
billion and Niobrara for $0.4 billion, both subject to customary closing
adjustments, as well as regulatory
and other approvals.
●
Reduced asset retirement obligations and accrued environmental costs by $2.3
billion, primarily due to
closed and pending dispositions.
●
Ended the year with cash, cash equivalents and restricted cash totaling $
5.4 billion and short-term
investments of $3.0 billion.
●
Recognized a $296 million after-tax impairment related
to the sale of our Niobrara interests in the Lower
48 segment.
●
Discontinued exploration activities in the Central Louisiana Austin Chalk trend
and recognized $197
million after-tax in leasehold impairment and dry hole expenses.
Operationally, we remain focused on safely executing our operating plan and maintaining
capital and cost
discipline.
Production of 1,348 MBOED increased 5 percent
or 65 MBOED in 2019 compared with 2018.
Production, excluding Libya, of 1,305 MBOED
increased 5 percent or 63 MBOED.
Underlying production,
which excludes Libya and the net volume impact
from closed dispositions and acquisitions
of 51 MBOED in
2019 and 47 MBOED in 2018, is used to measure
our ability to grow production organically.
Our underlying
production grew 5 percent in 2019 to 1,254 MBOED
from 1,195 MBOED in 2018.
On September 30, 2019, we completed the sale of
two ConocoPhillips U.K. subsidiaries to
Chrysaor E&P
Limited for proceeds of $2.2 billion after interest
and customary adjustments.
In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax
gain associated with this transaction.
Together the subsidiaries
sold our indirectly held exploration and production
assets in the U.K., including $1.8 billion
of ARO.
Annualized average production associated with the
U.K. assets sold was 50 MBOED in 2019.
Reserves
associated with the U.K. assets sold were 84 MMBOE
at the time of disposition.
Results of operations for the
U.K. are reported within our Europe and North
Africa segment.
In the second quarter of 2019, we completed the sale
of our 30 percent interest in the Greater Sunrise
Fields to
the government of Timor-Leste for $350 million and recognized
an after-tax gain of $52 million.
No
production or reserve impacts were associated
with the sale.
The Greater Sunrise Fields were included in
our
Asia Pacific and Middle East segment.
In October 2019, we entered into an agreement to sell
the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary
adjustments, with an effective date of January 1, 2019.
In addition, we will receive a payment of $75 million
upon final investment decision of the Barossa
development project.
These subsidiaries hold our 37.5 percent interest
in the Barossa Project and Caldita
Field, our 56.9 percent interest in the Darwin LNG
Facility and Bayu-Undan Field, our 40 percent
interest in
the Greater Poseidon Fields, and our 50 percent
interest in the Athena Field.
This transaction is expected to be
completed in the first quarter of 2020, subject to regulatory
approvals and the satisfaction of other specific
conditions precedent.
In 2019, production associated with the Australia-West assets to be sold was 48
MBOED.
Year
-end 2019
reserves associated with these assets were 17
MMBOE.
We will retain our 37.5
percent interest in the Australia Pacific LNG project
and operatorship of that project’s LNG facility.
Results
of operations for the subsidiaries to be sold are reported
within our Asia Pacific and Middle East segment.
In the fourth quarter of 2019, we signed an agreement
to sell our interests in the Niobrara shale play
for $380
million, plus customary adjustments,
and overriding royalty interests in certain
future wells.
We recorded an
after-tax impairment
of $296 million in the fourth quarter of 2019 to reduce
the carrying value to fair value.
In
2019, production from Niobrara was 11 MBOED.
Year
-end 2019 reserves associated with the
Niobrara assets
to be sold were 14 MMBOE.
This transaction is subject to regulatory approval
and other conditions precedent
and is expected to close in the first quarter
of 2020.
The Niobrara results of operations are reported
within our
Lower 48 segment.
For more information regarding the accounting impacts
of these transactions, see Note 5-Asset Acquisitions
and Dispositions,
in the Notes to Consolidated Financial
Statements.
Business Environment
Brent crude oil prices averaged $64 per barrel in 2019,
ranging from a low of $53 per barrel in January
to a
high of almost $75 per barrel in April.
The energy industry has periodically experienced
this type of volatility
due to fluctuating supply-and-demand conditions
and such volatility may persist for the foreseeable
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 foundational principles that underpin our value
proposition;
focus on financial returns through cash flow
expansion, maintain balance sheet strength and
deliver peer-leading distributions.
Operational and Financial Factors Affecting
Profitability
The focus areas we believe will drive our success
through the price cycles include:
●
Maintain a relentless focus on safety and environmental
stewardship.
Safety and environmental
stewardship, including the operating integrity
of our assets, remain our highest priorities,
and 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 both
the local and global environment and systematically
manage risk to drive sustainable business growth.
Demonstrating our commitment to sustainability
and environmental stewardship, on November 2017,
we announced our intention to target a 5 to 15 percent reduction
in our GHG emission
intensity by 2030.
In December 2018, we became a founding
member of the Climate Leadership
Council (CLC), an international policy institute
founded in collaboration with business and
environmental interests to develop a carbon dividend
plan.
Participation in the CLC provides another
opportunity for ongoing dialogue about carbon
pricing and framing the issues in alignment
with our
public policy principles.
We also belong to and fund Americans For Carbon Dividends, the education
and advocacy branch of the CLC.
In early 2019, we issued our first stand-alone
Climate-related Risk
Report and incorporated this into our website
during our annual Sustainability Report update.
Our
sustainability efforts continued through 2019 with a focus
on advancing our action plans for climate
change, biodiversity, water and human rights.
We are committed to building a learning organization
using human performance principles as we relentlessly
pursue improved HSE and operational
performance.
●
Focus on financial returns.
This is a core principle of our value proposition.
Our goal is to achieve
strong financial returns by exercising capital
discipline,
controlling our costs, and continually
optimizing our portfolio.
o
Maintain capital allocation discipline.
We participate in a commodity price-driven and
capital-intensive industry, with varying lead times from when an investment
decision is made
to the time an asset is operational and generates cash
flow.
As a result, we must invest
significant capital dollars to explore for new oil
and gas fields, develop newly discovered
fields, maintain existing fields, and construct pipelines
and LNG facilities.
We allocate
capital across a geographically diverse, low cost
of supply resource base, which combined
with legacy assets results in low production decline.
Cost of supply is the WTI equivalent
price that generates a 10 percent after-tax return
on a point-forward and fully burdened basis.
Fully burdened includes capital infrastructure,
foreign exchange, price related inflation and
G&A.
In setting our capital plans, we exercise a rigorous
approach that evaluates projects
using this cost of supply criteria, which should
lead to value maximization and cash flow
expansion using an optimized investment pace,
not production growth for growth’s sake.
Additional capital may be allocated toward growth,
but discipline will be maintained.
Our
cash allocation priorities call for the investment
of sufficient capital to sustain production and
pay the existing dividend.
In February 2020, we announced 2020 operating
plan capital of $6.5 billion to $6.7 billion.
The plan includes funding for ongoing development
drilling programs, major projects,
exploration and appraisal activities, as
well as base maintenance.
Capital spend is expected to
be higher in the first quarter largely from winter construction
and exploration and appraisal
drilling in Alaska.
This guidance does not include capital
for acquisitions.
o
Control costs and expenses.
Controlling operating and overhead costs,
without compromising
safety and environmental stewardship, is a high priority.
We monitor these costs using
various methodologies that are reported to senior management
monthly, on both an absolute-
dollar basis and a per-unit basis.
Managing operating and overhead costs is 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 impacts our ability to
deliver strong cash from operations.
In 2019, our production and operating expenses
were
two percent higher than 2018, primarily due to costs
associated with higher production
volumes, which grew five percent during the same
period.
o
Optimize our portfolio.
We continue to optimize our asset portfolio to focus on low cost of
supply assets that support our strategy.
In 2019, we continued to dispose of or market
certain
non-core assets, including the U.K., Australia-West and our Niobrara assets
in the Lower 48.
Additions to the portfolio were made in the Lower
48 with bolt-on interests and acreage
acquisitions,
in Alaska with the Nuna discovery acreage acquisition,
and internationally with
entrance into Argentina’s Neuquén and Austral Basins.
We will continue to evaluate our
assets to determine whether they compete for capital
within our portfolio and will optimize
the portfolio as necessary, directing capital towards the most competitive investments.
●
Maintain balance sheet strength.
We believe balance sheet strength is critical in a cyclical business
such as ours.
Our strong operating performance buffered by a solid
balance sheet enables us to deliver
on our priorities through the price cycles.
Our priorities include execution of our development
plans,
maintaining a growing dividend,
and repurchasing shares on a dollar cost
average basis.
●
Return value to shareholders.
We believe in delivering value to our shareholders via a growing,
sustainable dividend supplemented by share repurchases.
In 2019, we paid dividends on our common
stock of approximately $1.5 billion and repurchased
$3.5 billion of our common stock.
Combined,
our dividend and repurchases represented 45 percent
of our net cash provided by operating
activities.
Since we initiated our current share repurchase
program in late 2016, we have repurchased $9.6
billion
of shares.
Additionally, as of December 31, 2019, $5.4 billion of repurchase authority
remained of the
$15 billion share repurchase program our Board
of Directors had authorized.
In February 2020, we
announced that the Board of Directors approved
an increase to our repurchase authorization
from $15
billion to $25 billion, to support our plan for future
share repurchases.
Whether we undertake these
additional repurchases is ultimately subject to numerous
considerations, including market conditions
and other factors.
See Risk Factors “Our ability to declare and
pay dividends and repurchase shares is
subject to certain considerations.”
In October 2019, we announced that our Board
of Directors approved an increase to our quarterly
dividend of 38 percent to $0.42 per share.
●
Add to our proved reserve base.
We primarily add to our proved reserve base in three ways:
o
Successful exploration, exploitation and development
of new and existing fields.
o
Application of new technologies and processes
to improve recovery from existing fields.
o
Purchases of increased interests in existing
fields and bolt-on acquisitions.
Proved reserve estimates require economic production
based on historical 12-month, first-of-month,
average prices and current costs.
Therefore, 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,
as shown in our supplemental reserve table
disclosures.
In 2019, our reserve replacement, which included
a net decrease of 0.1 billion BOE from
sales and purchases, was 100 percent.
Increased crude oil reserves accounted for approximately
percent of the total change in reserves. Our organic reserve
replacement, which excludes the impact of
sales and purchases, was 117 percent in 2019.
Approximately 50 percent of organic reserve additions
were from Lower 48 unconventional assets.
The remaining additions were evenly distributed
across
the other operating segments.
In the five years ended December 31, 2019, our reserve
replacement was negative 34 percent,
reflecting the impact of asset dispositions and lower
prices during that period.
Our organic reserve
replacement during the five years ended December
31, 2019, which excludes a decrease of 2.0 billion
BOE related to sales and purchases, was 40 percent,
reflecting development activities as
well as lower
prices during that period.
Historically, our reserve replacement has varied considerably year to year contingent
upon the timing
of major projects which may have long lead times
between capital investment and production.
In the
last several years, more of our capital has been
allocated to short cycle time, onshore,
unconventional
plays.
Accordingly, we believe our recent success in replacing reserves can be viewed
on a trailing
three-year basis.
In the three years ended December 31, 2019, our reserve
replacement was 23 percent, reflecting the
impact of asset dispositions during that period.
Our organic reserve replacement during the three
years ended December 31, 2019, which excludes a
decrease of 1.8 billion BOE related to sales
and
purchases, was 143 percent, reflecting reserve
additions from development activities.
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 replace our production
over subsequent years.
●
Apply technical capability.
We leverage our knowledge and technology to create value and safely
deliver on our plans.
Technical strength is part of our heritage and allows us to economically
convert
additional resources to reserves, achieve greater
operating efficiencies and reduce our environmental
impact.
Companywide, we continue to evaluate potential
solutions to leverage knowledge of
technological successes across our operations.
We have embraced the digital transformation and are using digital innovations to
work and operate
more efficiently.
Predictive analytics have been adopted in our operations
and planning process.
Artificial intelligence, machine learning and
deep learning are being used for seismic
advancements.
●
Attract, develop and retain a talented work force.
We strive to attract, develop and retain individuals
with the knowledge and skills to implement
our business strategy and who support our values
and
ethics.
We offer university internships across multiple disciplines to attract the best early career
talent.
We also recruit experienced hires to fill critical skills and maintain a broad range
of expertise
and experience.
We promote continued learning, development and technical training through
structured development programs designed to enhance
the technical and functional skills
of our
employees.
Other Factors Affecting Profitability
Other significant factors that can affect our profitability
include:
●
Energy commodity prices.
Our earnings and operating cash flows generally
correlate with industry
price levels for crude oil and natural gas.
Industry price levels are subject to factors external
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,
environmental laws, tax regulations, governmental
policies and weather-related disruptions.
The
following graph depicts the average benchmark
prices for WTI crude oil, Brent crude oil
and U.S.
Henry Hub natural gas:
Brent crude oil prices averaged $64.30 per barrel
in 2019, a decrease of 9 percent compared
with
$71.04 per barrel in 2018.
Similarly, WTI crude oil prices decreased 12 percent from $64.92 per
barrel in 2018 to $57.02 per barrel in 2019.
Crude oil prices weakened year over year primarily
due to
ample global supplies and a decelerating global
economy.
Henry Hub natural gas price averages decreased
15 percent from $3.09 per MMBTU in 2018 to
$2.63
per MMBTU in 2019.
Natural gas prices weakened in 2019 versus the
prior year due to strong
production, while demand growth was dampened
by mild weather.
Our realized NGL prices decreased 34 percent from
$30.48 per barrel in 2018 to $20.09 per barrel
in
2019.
NGL prices weakened year over year due to
strong supply growth with only moderate demand
growth.
Our realized bitumen price increased 42 percent
from $22.29 per barrel in 2018 to $31.72 per
barrel in
2019.
Curtailment orders imposed by the Alberta
Government, which limited production from
the
province starting January 2019, provided strength
to the WCS differential to WTI at Hardisty.
We
continue to optimize bitumen price realizations
through the utilization of downstream transportation
solutions and implementation of alternate blend capability
which results in lower diluent costs.
Our worldwide annual average realized price decreased
9 percent from $53.88
per BOE in 2018 to
$48.78
per BOE in 2019 due to lower realized oil,
natural gas and NGL 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.
●
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, or a
decision to dispose of an asset leads to
a write-down
to its fair value.
We may also invest large amounts of money in exploration which, if exploratory
drilling proves unsuccessful, could lead to a material
impairment of leasehold values.
As we optimize
our assets in the future, it is reasonably possible
we may incur future losses upon sale or
impairment
charges to long-lived assets used in operations, investments
in nonconsolidated entities accounted for
under the equity method, and unproved properties.
A sustained decline in the current and long-term
outlook on gas price could affect the carrying value
of certain Lower 48 non-core gas assets and it
is
reasonably possible this could result in a future
non-cash impairment.
For additional information on
our impairments in 2019, 2018 and 2017, see
Note 9-Impairments, in the Notes to Consolidated
Financial Statements.
●
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 the U.S.
Civil
unrest or strained relationships with governments
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
Full-year 2020 production is expected to be 1,230
MBOED to 1,270 MBOED, including the impact
of a recent
third-party pipeline outage on the Kebabangan
Field in Malaysia.
First-quarter 2020 production is expected to
be 1,240 MBOED to 1,280 MBOED.
Production guidance for 2020 excludes Libya.
Operating Segments
We manage our operations through six operating segments, which are primarily
defined by geographic region:
Alaska, Lower 48, Canada, Europe and North
Africa, Asia Pacific and Middle East, and Other
International.
Corporate and Other represents 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
This section of the Form 10-K
discusses year-to-year comparisons between 2019
and 2018.
For discussion of
year-to-year comparisons between 2018 and 2017, see
"Management's Discussion and Analysis
of Financial
Condition and Results of Operations" in Part II, Item
7 of our 2018 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
Alaska
$
1,520
1,814
1,466
Lower 48
1,747
(2,371)
Canada
2,564
Europe and North Africa
2,724
1,866
Asia Pacific and Middle East
1,929
2,070
(1,098)
Other International
Corporate and Other
(1,667)
(2,136)
Net income (loss) attributable to ConocoPhillips
$
7,189
6,257
(855)
2019 vs. 2018
Net income attributable to ConocoPhillips
increased $932 million in 2019.
The increase was mainly due to:
●
A $2.1 billion after-tax gain associated with the
completion of the sale of two ConocoPhillips
U.K.
subsidiaries to Chrysaor E&P Limited.
●
An unrealized gain of $649 million after-tax
on our Cenovus Energy (CVE) common shares in 2019,
as compared to a $436 million after-tax unrealized
loss on those shares in 2018.
●
Higher crude oil sales volumes due to growth in the
Lower 48 unconventionals and from the
acquisition of incremental interests in operated
assets in Alaska during the second and
fourth quarters
of 2018.
●
The absence of premiums on early debt retirements
totaling $195 million after-tax.
●
A $164 million income tax benefit related to
deepwater incentive tax credits recognized for
Malaysia
Block G.
●
A $151
million income tax benefit related to the
revaluation of deferred tax assets following
finalization of rules relating to the 2017 Tax Cuts and Jobs Act.
These increases in net income were partly offset by:
●
Lower realized crude oil, natural gas and NGL
prices.
●
The absence of a $774 million after-tax gain on the
Clair disposition in the U.K.
●
A $296
million after-tax impairment related to
the sale of our Lower 48 Niobrara interests.
●
Lower equity in earnings of affiliates due to $120 million
of impairments to equity method
investments in our Lower 48 segment and a $118 million reduction
in equity earnings at QG3 in our
Asia Pacific and Middle East segment due to a deferred
tax adjustment.
●
Higher exploration expenses, primarily in
our Lower 48 segment due to $197 million after-tax
of
leasehold impairment and dry hole costs associated
with our decision to discontinue exploration
activities in the Central Louisiana Austin
Chalk trend.
Income Statement Analysis
2019 vs. 2018
Sales and other operating revenues decreased 11 percent in 2019,
mainly due to lower realized crude oil,
natural gas and NGL prices, partly offset by higher sales
volumes of crude oil in the Lower 48 and Alaska.
Equity in earnings of affiliates decreased $295 million
in 2019, primarily due to impairments of equity
method
investments in our Lower 48 segment totaling
$155 million.
Additionally, equity earnings decreased $118
million resultant from a deferred tax adjustment
at QG3,
reported in our Asia Pacific and Middle East segment.
For more information related to these items,
see Note 3-Variable Interest Entities and Note 5-Asset
Acquisitions and Dispositions, in the Notes to
Consolidated Financial Statements.
Gain on dispositions increased $903 million
in 2019, primarily due to a $1.7
billion before-tax gain associated
with the completion of the sale of two ConocoPhillips
U.K. subsidiaries to Chrysaor E&P Limited.
Partly
offsetting this increase, was the absence of a $715 million
before-tax gain on the sale of a ConocoPhillips
subsidiary to BP in 2018,
which held 16.5 percent of our 24 percent interest
in the BP-operated Clair Field in
the U.K.
For additional information related to these dispositions,
see Note 5-Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial
Statements.
Other income increased $1,185 million in 2019, primarily
due to an unrealized gain of $649 million before-tax
on our CVE common shares in 2019, and the absence
of a $437 million before-tax unrealized loss
on those
shares in 2018.
For discussion of our CVE shares, see Note
7-Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements.
Purchased commodities decreased 17 percent in
2019, primarily due to lower natural gas
and crude oil prices.
Selling, general and administrative expenses increased
$155 million in 2019, primarily due to higher
costs
associated with compensation and benefits,
including mark to market impacts of certain
key employee
compensation programs, and increased facility
costs.
Exploration expenses increased $374 million
in 2019, primarily due to higher leasehold impairment
and dry
hole costs,
mainly in our Lower 48 segment,
and higher exploration G&A expenses.
In 2019, we recorded a
$141 million before-tax leasehold impairment
expense due to our decision to discontinue
exploration activities
in the Central Louisiana Austin Chalk trend and
expensed $111 million of dry hole costs related to this play.
Impairments increased $378 million in
2019, mainly due to a $379 million before-tax impairment
related to the
sale of our Niobrara interests in the Lower 48 segment.
For additional information, see Note 5-Asset
Acquisitions and Dispositions and Note 9-Impairments,
in the Notes to Consolidated Financial Statements.
Other expenses decreased $310 million in
2019, primarily due to the absence of a $206
million before-tax
expense for premiums on early debt retirements
and lower pension settlement expense.
See Note 19-Income Taxes, in the Notes to Consolidated Financial Statements,
for information regarding our
income tax provision (benefit) and effective tax rate.
Summary Operating Statistics
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)
2,805
2,774
3,270
Total Production
(MBOED)
1,348
1,283
1,377
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
$
60.99
68.13
51.96
Natural gas liquids (per bbl)
20.09
30.48
25.22
Bitumen (per bbl)
31.72
22.29
22.66
Natural gas (per mcf)
5.03
5.65
4.07
Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other
$
Leasehold impairment
Dry holes
$
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on
a worldwide
basis.
At December 31, 2019, our operations were
producing in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, China, Malaysia, Qatar and
Libya.
2019 vs. 2018
Total production, including Libya, of 1,348 MBOED increased 65 MBOED
or 5 percent in 2019 compared
with 2018,
primarily due to:
●
New wells online in the Lower 48.
●
An increased interest in the Western North Slope (WNS) and Greater Kuparuk Area
(GKA) of Alaska
following acquisitions closed in 2018.
●
Higher production in Norway due to drilling activity
and the startup of Aasta Hansteen in December
2018.
The increase in production during 2019 was
partly offset by:
●
Normal field decline.
●
Disposition impacts from the U.K. and non-core
asset sales in the Lower 48.
Production excluding Libya was 1,305 MBOED in
2019 compared with 1,242 MBOED in 2018,
an increase of
63 MBOED or 5 percent.
Underlying production, which excludes Libya and
the net volume impact from
closed dispositions and acquisitions of 51 MBOED
in 2019 and 47 MBOED in 2018, is used to measure
our
ability to grow production organically.
Our underlying production grew 5 percent to 1,254
MBOED in 2019
from 1,195 MBOED in 2018.
Alaska
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
1,520
1,814
1,466
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil (per bbl)
$
64.12
70.86
53.33
Natural gas (per mcf)
3.19
2.48
2.72
The Alaska segment primarily explores for, produces, transports
and markets crude oil, NGLs and natural gas.
In 2019, Alaska contributed 25 percent of our
worldwide liquids production and less than 1 percent
of our
natural gas production.
2019 vs. 2018
Alaska reported earnings of $1,520 million in
2019, compared with earnings of $1,814 million
in 2018.
The
decrease in earnings was mainly due to lower
realized crude oil prices and higher production
and operating and
DD&A expenses associated with incremental volumes
from acquisitions completed during 2018.
Additionally, earnings were lower due to the absence of a $98 million tax valuation
allowance reduction,
the
absence of a $79 million after-tax benefit resulting
from an accrual reduction due to a transportation
cost ruling
by the FERC,
and $62 million less in enhanced oil recovery
credits.
Partly offsetting these decreases in
earnings, were higher crude oil sales volumes
due to the GKA and WNS acquisitions completed
in 2018.
Average production increased 32 MBOED in 2019 compared with 2018, primarily
due to acquisitions at GKA
and WNS in 2018, which provided an incremental
38 MBOED of production in 2019, as well as volumes
from
new wells online.
These production increases were partly offset by normal
field decline.
Acquisition Update
In the third quarter of 2019, we completed the
Nuna discovery acreage acquisition for approximately
$100
million, expanding the Kuparuk River Unit by
21,000 acres and leveraging legacy infrastructure.
Lower 48
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
1,747
(2,371)
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil (per bbl)
$
55.30
62.99
47.36
Natural gas liquids (per bbl)
16.83
27.30
22.20
Natural gas (per mcf)
2.12
2.82
2.73
The Lower 48 segment consists of operations located
in the contiguous U.S. and the Gulf of Mexico.
During
2019, the Lower 48 contributed 39 percent of our
worldwide liquids production and 22 percent
of our natural
gas production.
2019 vs. 2018
Lower 48 reported earnings of $436 million in
2019, compared with $1,747 million in 2018.
Earnings
decreased primarily due to lower realized crude oil,
NGL and natural gas prices; higher DD&A due to
increased production volumes; a $301 million after-tax
impairment of our Niobrara assets;
higher exploration
expenses, primarily due to a combined $197 million
after-tax of leasehold impairment and dry
hole costs
associated with our decision to discontinue exploration
activities in the Central Louisiana Austin
Chalk; and
lower earnings in equity
affiliates due to a combined $120 million after-tax
of impairments associated with a
fair value reduction of our investment in MWCC
and the disposition of our interests in the
Golden Pass LNG
Terminal and Golden Pass Pipeline.
Partly offsetting the decrease in earnings were increased
crude oil and
NGL sales volumes in the Eagle Ford, Bakken
and Permian Unconventional.
For additional information related to our impairment
of MWCC, see Note 3-Variable Interest Entities in the
Notes to Consolidated Financial Statements.
For more information related to the sale of our interests
in
Golden Pass LNG Terminal and Golden Pass Pipeline, see Note 5-Asset
Acquisitions and Dispositions in the
Notes to Consolidated Financial Statements.
Total average production increased 54 MBOED in 2019 compared with 2018.
The increase was primarily due
to new production from unconventional assets in
Eagle Ford, Bakken and the Permian Basin,
partly offset by
normal field decline.
Additionally, production decreased by 10 MBOED due to non-core dispositions
in 2018.
Asset Dispositions
Update
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 have also entered into agreements to amend our contractual
obligations for retaining use of the facilities.
As a result of entering into these agreements, we recognized
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.
See Note 15-Fair Value Measurement in the Notes to Consolidated Financial Statements, for
additional
information.
In the fourth quarter of 2019, we sold our interests
in the Magnolia field and platform and recognized
an after-
tax gain of $63 million.
Production from Magnolia in 2019 was less
than one MBOED.
In the fourth quarter of 2019, we signed an agreement
to sell our interests in the Niobrara shale
play for $380
million, plus customary adjustments,
and overriding royalty interests in certain
future wells.
We recorded an
after-tax impairment of $301 million in
the fourth quarter to reduce the carrying value to
fair value.
Production from Niobrara was approximately 11 MBOED in 2019.
This transaction is subject to regulatory
approval and other conditions precedent and
is expected to close in the first quarter
of 2020.
In January 2020, we entered into an agreement to
sell our interests in certain non-core properties
in the Lower
48 segment for $186 million, plus customary
adjustments.
The assets met the held for sale criteria
in January
2020 and the transaction is expected to be completed
in the first quarter of 2020.
No gain or loss is anticipated
on the sale.
This disposition will not have a significant
impact on Lower 48 production.
For additional information on these transactions,
see Note 5-Asset Acquisitions and Dispositions,
in the
Notes to Consolidated Financial Statements.
Canada
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
2,564
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
-
Bitumen (MBD)
Consolidated operations
Equity affiliates
-
-
Total bitumen
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil (per bbl)
$
40.87
48.73
43.69
Natural gas liquids (per bbl)
19.87
43.70
21.51
Bitumen (dollars per bbl)*
Consolidated operations
31.72
22.29
21.43
Equity affiliates
-
-
23.83
Total bitumen
31.72
22.29
22.66
Natural gas (per mcf)
0.49
1.00
1.93
*Average prices for sales of bitumen produced during 2018 and 2019 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 2019, Canada contributed 7 percent of our
worldwide
liquids production and less than one percent of
our worldwide natural gas production.
2019 vs. 2018
Canada operations reported earnings of $279 million
in 2019 compared with $63 million in 2018.
Earnings
increased mainly due to higher realized bitumen
prices,
a $68 million tax benefit primarily comprised
of a
previously unrecognizable tax basis related to
a tax settlement,
lower DD&A expense due to lower rates from
reserve additions,
lower production and operating expenses,
and a $25 million tax benefit due to a four year
phased four percent reduction in Alberta’s corporate income tax rate.
Partly offsetting the increase in earnings
were lower sales volumes due to a planned turnaround
at Surmont, lower production due to a mandated
production curtailment imposed by the Alberta
government in January 2019, and the absence of
an $80 million
tax restructuring benefit.
Total average production decreased 7 MBOED in 2019 compared with 2018.
The production decrease was
primarily due to a turnaround at Surmont, which
had an annualized average impact of 3 MBOED,
and a
mandated production curtailment imposed by the
Alberta government,
which also impacted production by 3
MBOED.
The curtailment program is established and administered
by the Alberta Energy Regulator under the
Curtailment Rules regulation, which is currently
set to expire on December 31, 2020.
This program is
intended to strengthen the WCS differential to WTI at
Hardisty.
Asset Disposition
On May 17, 2017, we completed the sale of our
50 percent nonoperated interest in the FCCL
Partnership, as
well as the majority of our western Canada gas
assets to Cenovus Energy.
Consideration for the transaction
was $11.0 billion in cash after customary adjustments, 208 million
Cenovus Energy common shares and a five
year uncapped contingent payment.
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.
During 2019 and 2018, we recorded after-tax gains
on dispositions for these contingent payments of
$84
million and $68 million,
respectively.
See Note 5-Asset Acquisitions and Dispositions
in the Notes to
Consolidated Financial Statements, for additional
information.
Europe and North Africa
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
2,724
1,866
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production
(MBOED)
Average Sales Prices
Crude oil (dollars per bbl)
$
64.94
70.71
54.21
Natural gas liquids (per bbl)
29.37
36.87
34.07
Natural gas (per mcf)
4.92
7.65
5.70
The Europe and North Africa segment consisted
of operations principally located in the Norwegian
and U.K.
sectors of the North Sea, the Norwegian Sea and
Libya.
In 2019, our Europe and North Africa operations
contributed 16 percent of our worldwide liquids production
and 17 percent of our natural gas production.
2019 vs. 2018
Earnings for Europe and North Africa operations
of $2,724 million increased $858 million
in 2019 compared
with 2018.
The increase in earnings was primarily
due to a $2.1 billion after-tax gain associated with
the
completion of the sale of two ConocoPhillips
U.K. subsidiaries to Chrysaor E&P Limited.
Earnings also
increased due to the cessation of DD&A in the second
quarter of 2019 for our disposed U.K. subsidiaries
when
these assets became held-for-sale.
Partly offsetting the increase in earnings were the absence
of a $774 million
after-tax gain related to the sale of a ConocoPhillips
subsidiary to BP, which held 16.5 percent of our 24
percent interest in the BP-operated Clair Field
in the U.K.; lower sales volumes primarily
due to the U.K.
disposition to Chrysaor completed September 30,
2019; and lower realized natural gas and crude
oil prices.
Average production decreased 17 MBOED in 2019, compared with 2018.
The decrease was mainly due to
normal field decline and a 20 MBOED disposition
impact from the sale of our U.K. assets to Chrysaor
completed September 30, 2019.
Partly offsetting these production decreases were volumes
from new wells
online in Norway,
including the Aasta Hansteen Field which
achieved first production in December of 2018.
Asset Disposition Update
On September 30, 2019, we completed the sale of
two ConocoPhillips U.K. subsidiaries to
Chrysaor E&P
Limited for proceeds of $2.2 billion after interest
and customary adjustments.
In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax
gain associated with this transaction.
Together the subsidiaries
sold indirectly held our exploration and production
assets in the U.K., including $1.8 billion
of ARO.
Annualized average production associated with the
U.K. assets sold was 50 MBOED in 2019.
Reserves
associated with the U.K. assets sold were 84 MMBOE
at the time of disposition.
For additional information,
see Note 5-Asset Acquisitions and Dispositions
in the Notes to Consolidated Financial
Statements.
Asia Pacific and Middle East
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
1,929
2,070
(1,098)
Average Net Production
Crude oil (MBD)
Consolidated operations
Equity affiliates
Total crude oil
Natural gas liquids (MBD)
Consolidated operations
Equity affiliates
Total natural gas liquids
Natural gas (MMCFD)
Consolidated operations
Equity affiliates
1,052
1,031
1,007
Total natural gas
1,689
1,657
1,694
Total Production
(MBOED)
Average Sales Prices
Crude oil (dollars per bbl)
Consolidated operations
$
65.02
70.93
54.38
Equity affiliates
61.32
72.49
54.76
Total crude oil
64.52
71.14
54.43
Natural gas liquids (dollars per bbl)
Consolidated operations
37.85
47.20
41.37
Equity affiliates
36.70
45.69
38.74
Total natural gas liquids
37.10
46.13
39.75
Natural gas (dollars per mcf)
Consolidated operations
5.91
6.15
4.98
Equity affiliates
6.29
6.06
4.27
Total natural gas
6.15
6.09
4.55
The Asia Pacific and Middle East segment has
operations in China, Indonesia, Malaysia,
Australia, Timor-Leste
and Qatar.
During 2019,
Asia Pacific and Middle East contributed 13 percent
of our worldwide liquids
production and 60 percent of our natural gas production.
2019 vs. 2018
Asia Pacific and Middle East reported earnings
of $1,929 million in 2019, compared with
$2,070 million in
2018.
The decrease in earnings was mainly due to
lower realized crude oil, NGL and natural gas
prices;
lower
LNG and crude oil sales volumes; and lower equity
in earnings of affiliates, primarily due to a deferred
tax
adjustment at QG3 that resulted in a $118 million reduction to equity
earnings.
Partly offsetting this decrease in
earnings was a $164 million income tax benefit
related to deepwater incentive tax credits
from the Malaysia
Block G and a $52 million after-tax gain on disposition
of our interest in the Greater Sunrise Fields.
Average production increased 1 percent in 2019, compared with 2018.
The increase was primarily due to new
production from Malaysia, including first gas
supply from KBB to PFLNG1 in the second quarter
of 2019 and
first oil from Gumusut Phase 2 in the third quarter
of 2019;
and new wells online in China, including
Bohai
Phase 3.
Partly offsetting this production increase was normal
field decline.
Asset Dispositions Update
In the second quarter of 2019, we recognized an
after-tax gain of $52 million upon completion
of the sale of our
30 percent interest in the Greater Sunrise Fields
to the government of Timor-Leste for $350 million.
No
production or reserve impacts were associated
with the sale.
In October 2019, we entered into an agreement to sell
the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary
adjustments, with an effective date of January 1, 2019.
In
addition, we will receive a payment of $75 million
upon final investment decision of the Barossa development
project.
These subsidiaries hold our 37.5 percent interest
in the Barossa Project and Caldita Field, our 56.9
percent interest in the Darwin LNG Facility
and Bayu-Undan Field, our 40 percent interest
in the Greater
Poseidon Fields, and our 50 percent interest in
the Athena Field.
This transaction is expected to be completed in
the first quarter of 2020, subject to regulatory approvals
and the satisfaction of other specific conditions
precedent.
In 2019, production associated with the
Australia-West assets to be sold was 48 MBOED.
Year
-end
2019 reserves associated with these assets were
17 MMBOE.
We will retain our 37.5 percent interest in the
Australia Pacific LNG project and operatorship
of that project’s LNG facility.
See Note 5-Asset Acquisitions and Dispositions
in the Notes to Consolidated Financial
Statements, for
additional information related to these dispositions.
Other International
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
The Other International segment includes exploration
activities in Colombia, Chile and Argentina and
contingencies associated with prior operations.
2019 vs. 2018
Other International operations reported earnings
of $263 million in 2019, compared with
earnings of $364
million in 2018.
The decrease in earnings was primarily due
to the recognition of $417 million after-tax
in
other income related to a settlement agreement
with PDVSA in 2018, compared with $317 million
after-tax
associated with this settlement agreement in 2019.
In 2018 and 2019, we collected approximately
$0.8 billion of the $2.0 billion settlement with
PDVSA.
PDVSA has defaulted on its remaining payment obligations
under this agreement, we are therefore now forced
to incur additional costs as we seek to recover
any unpaid amounts under the agreement.
For additional
information, see Note 13-Contingencies and Commitments
in the Notes to Consolidated Financial
Statements.
Argentina
In January 2019,
we secured a 50 percent nonoperated interest
in the El Turbio Este Block, within the Austral
Basin in southern Argentina.
In 2019, we acquired and processed 3-D
seismic covering 500 square miles,
with
evaluation of the data ongoing.
In November 2019, we acquired interests in
two nonoperated blocks in the Neuquén Basin
targeting the Vaca
Muerta play.
We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest
in the
Aguada Federal Block.
In Bandurria Norte, 1 vertical and 4 horizontal
wells were tested and shut-in during
2019.
In Aguada Federal, 2 horizontal wells
were being tested at the end of the year.
Corporate and Other
Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
Net interest
$
(604)
(680)
(739)
Corporate general and administrative expenses
(252)
(91)
(193)
Technology
Other
(1,005)
(1,224)
$
(1,667)
(2,136)
2019 vs. 2018
Net interest consists of interest and financing expense,
net of interest income and capitalized interest.
Net
interest decreased $76 million in 2019 compared
with 2018,
primarily due to lower capitalized interest
on
projects; increased interest income from holding
higher cash balances; and lower interest on debt expense
resultant from the retirement of $4.7 billion of
debt in 2018; partly offset by the absence of an accrual
reduction due to a transportation cost ruling
by the FERC.
Corporate G&A expenses include compensation
programs and staff costs.
These costs increased by $161
million in 2019 compared with 2018, primarily
due to higher costs associated with compensation
and benefits,
including certain key employee compensation
programs and higher facility costs.
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 and LNG.
Earnings from Technology increased by $14 million in 2019 compared with
2018,
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, unrealized holding gains or losses
on equity securities, and
pension settlement expense.
Earnings in “Other” increased by $1,776 million
in 2019 compared with 2018,
primarily due to an unrealized gain of $649 million
after-tax on our CVE common shares in
2019, and the
absence of a $436
million after-tax unrealized loss on those
shares in 2018.
Additionally, earnings increased
due to the absence of $195 million in
premiums on the early retirement of debt, lower pension
settlement
expense, and a $151 million tax benefit related
to the revaluation of deferred tax assets following
finalization
of rules related to the 2017 Tax Cuts and Jobs Act.
See Note 19-Income Taxes, in the Notes to Consolidated
Financial Statements, for additional information
related to the 2017 Tax Cuts and Jobs Act.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
Net cash provided by operating activities
$
11,104
12,934
7,077
Cash and cash equivalents
5,088
5,915
6,325
Short-term debt
2,575
Total debt
14,895
14,968
19,703
Total equity
35,050
32,064
30,801
Percent of total debt to capital*
%
Percent of floating-rate debt to total debt
%
*Capital includes total debt and total equity.
To meet our short-
and long-term liquidity requirements, we look
to a variety of funding sources, including
cash generated from operating activities,
proceeds from asset sales, our commercial paper
and credit facility
programs and our ability to sell securities
using our shelf registration statement.
In 2019, the primary uses of
our available cash were $6,636 million to support
our ongoing capital expenditures and investments
program;
$3,500 million to repurchase our common stock;
$2,910 million net purchases of investments,
and $1,500
million to pay dividends on our common stock.
During 2019, cash and cash equivalents decreased
by $827
million to $5,088 million.
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, share repurchases,
dividend
payments and required debt payments.
Our commitment to disciplined execution of these
funding requirements includes cash
investment strategies
that position us for success in an environment
of short-term price volatility as well as
extended downturns in
commodity prices.
The primary objectives of these cash investment
strategies in priority order are to protect
principal, maintain liquidity, and provide yield and total returns.
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
price downturns and to capture opportunities outside
a given operating plan may be invested in
instruments
with maturities greater than one year.
For additional information, see Note 1-Accounting
Policies and Note
14-Derivative and Financial Instruments.
Significant Changes in Capital
Operating Activities
During 2019, cash provided by operating activities
was $11,104 million, a 14 percent decrease from 2018.
The
decrease was primarily due to lower prices, lower
collections related to settlements reached with
Ecuador and
PDVSA, and a pension contribution made in conjunction
with the sale of two U.K. subsidiaries, partially
offset
by higher volumes.
While the stability of our cash flows from operating
activities benefits from geographic diversity, 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 1,348 MBOED in 2019.
Full-year production excluding Libya averaged
1,305
MBOED in 2019
and is expected to be 1,230 to 1,270 MBOED
in 2020.
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; 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.
In 2019,
our reserve replacement, which included a net decrease
of 0.1 billion BOE from sales and purchases,
was 100
percent.
Increased crude oil reserves accounted for approximately
55 percent of the total change in reserves.
Our organic reserve replacement, which excludes the
impact of sales and purchases, was 117 percent
in 2019.
Approximately 51 percent of organic reserve additions
are from Lower 48, 13 percent from Alaska,
12 percent
from Canada, 12 percent from Europe and North
Africa and 12 percent from Asia Pacific and Middle
East.
In the five years ended December 31, 2019, our reserve
replacement, which included a decrease
of 2.0 billion
BOE from sales and purchases, was negative 34
percent, reflecting the impact of asset dispositions
and lower
prices during that period.
Our organic reserve replacement during the five years
ended December 31, 2019,
was 40
percent, reflecting development activities
as well as lower prices during that period.
Historically our reserve replacement has varied
considerably year to year contingent upon the timing
of major
projects which may have long lead times between
capital investment and production.
In the last several years,
more of our capital has been allocated to short cycle
time, onshore, unconventional plays.
Accordingly, we
believe our recent success in replacing reserves can
be viewed on a trailing three-year basis.
In the three years ended December 31, 2019, our reserve
replacement was 23 percent, reflecting the impact
of
asset dispositions during that period.
Our organic reserve replacement during the three years
ended December
31, 2019, which excludes a decrease of 1.8 billion
BOE related to sales and purchases, was 143 percent,
reflecting reserve additions from development activities.
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. For additional information about
our
2020 capital budget, see the “2020 Capital Budget”
section within “Capital Resources and Liquidity”
and for
additional information on proved reserves, including
both developed and undeveloped reserves, see the
“Oil
and Gas Operations” section of this report.
As discussed in the “Critical Accounting Estimates”
section, engineering estimates of proved
reserves are
imprecise; therefore, each year reserves may be revised
upward or downward due to the impact of changes
in
commodity prices or as more technical data becomes
available on reservoirs.
We have reported revisions as
increases to reserves in the current period, however
in prior periods,
reported revisions as decreases to
reserves. It is not possible to reliably predict
how revisions will impact reserve quantities
in the future.
Investing Activities
Proceeds from asset sales in 2019 were $3.0 billion.
We
completed the sale of two ConocoPhillips U.K.
subsidiaries to Chrysaor E&P Limited for $2.2
billion.
We also completed the sale of several assets including
our 30 percent interest in the Greater Sunrise Fields
for $350 million and received $106 million
of contingent
payments from Cenovus Energy.
In the fourth quarter of 2019, we entered into an
agreement to sell the subsidiaries that hold
our Australia-West
assets and operations to Santos for $1.39 billion,
plus customary adjustments.
In addition, we will receive a
payment of $75 million upon final investment
decision of the Barossa development project.
Also in the fourth
quarter of 2019, we signed an agreement to sell
our interests in the Niobrara shale play
for $380 million, plus
customary adjustments,
and overriding royalty interests in certain
future wells.
Both transactions are subject to
regulatory approval and other conditions precedent
and expected to close in the first quarter of 2020.
Investing activities in 2019 also included net purchases
of $2.9 billion of investments in short-term
and long-
term financial instruments. These investments include
time deposits, commercial paper as well as debt
securities classified as available for sale.
The investment in short-term instruments
was $2.8 billion, the
remaining $0.1 billion was invested in long-term
debt securities.
For additional information, see Note 14-
Derivative and Financial Instruments.
Proceeds from asset sales in 2018 were $1.1 billion.
We completed several undeveloped acreage transactions
in our Lower 48 segment for a total of $267 million
after customary adjustments and another transaction
in our
Lower 48 segment for $112 million after customary adjustments.
We completed the sale of our interests in the
Barnett to Lime Rock Resources for $196 million
after customary adjustments.
We also completed the sale of
a ConocoPhillips subsidiary to BP and received
$253 million net proceeds.
The subsidiary held 16.5 percent
of our 24 percent interest in the BP-operated
Clair Field in the U.K.
During 2018, we received $95 million of
contingent payments from Cenovus Energy.
For additional information on our dispositions,
see Note 5-Asset Acquisitions and Dispositions
in the Notes
to Consolidated Financial Statements.
Commercial Paper and Credit Facilities
We have a revolving credit facility totaling $6.0 billion, expiring in May 2023.
Our revolving credit facility
may be used for direct bank borrowings, the issuance
of letters of credit totaling up to $500 million, or
as
support for our commercial paper program.
The revolving credit facility is broadly syndicated
among financial
institutions and does not contain any material
adverse change provisions or any covenants
requiring
maintenance of specified financial ratios or credit
ratings.
The facility agreement contains a cross-default
provision relating to the failure to pay principal or interest
on other debt obligations of $200 million or more
by ConocoPhillips, or any of its consolidated subsidiaries.
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 the ConocoPhillips
Company $6.0 billion commercial paper program,
which is primarily a funding source for short-term
working capital needs.
Commercial paper maturities are
generally limited to 90 days.
We had no commercial paper outstanding in programs in place at December 31,
2019 or December 31, 2018.
We had no direct outstanding borrowings or letters of credit under the revolving
credit facility at December 31, 2019 and December
31, 2018.
Since we had no commercial paper outstanding
and had issued no letters of credit, we had access to
$6.0 billion in borrowing capacity under our revolving
credit facility at December 31, 2019.
Our current long-term debt ratings remained
unchanged in 2019 and are as follows:
Fitch - “A” with a “stable”
outlook; Moody’s Investors Services - “A3” with a “stable” outlook; and
Standard & Poor’s - “A” with a
stable outlook.
We do not have any ratings triggers on any of our corporate debt that would
cause an
automatic default, and thereby impact our access
to liquidity, in the event of a downgrade of our credit rating.
If our credit rating were downgraded, it could
increase the cost of corporate debt available
to us and 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, 2019 and 2018, we had direct
bank letters of credit of $277 million
and $323 million, respectively, which secured performance obligations related to
various purchase
commitments incident to the ordinary conduct of business.
In the event of credit ratings downgrades, we may
be required to post additional letters of
credit.
Shelf Registration
We have a universal shelf registration statement on file with the SEC under which
we, as a well-known
seasoned issuer, have the ability to issue and sell an indeterminate
amount of various types of debt and equity
securities.
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations
and consistent with normal industry practice,
we enter into
numerous agreements with other parties to pursue
business opportunities, which share costs
and apportion
risks among the parties as governed by the agreements.
For information about guarantees, see Note 12-Guarantees,
in the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
Capital Requirements
For information about our capital expenditures
and investments, see the “Capital Expenditures”
section.
Our debt balance at December 31, 2019, was $14,895
million, a decrease of $73 million from the balance
at
December 31, 2018.
For more information on Debt, see Note 11-Debt, in the Notes
to Consolidated
Financial Statements.
On January 30, 2019, we announced a quarterly
dividend of $0.305 per share.
The dividend was paid on
March 1, 2019, to stockholders of record at the close
of business on February 11, 2019.
On May 1, 2019, we
announced a quarterly dividend of $0.305 per share.
The dividend was paid on June 3, 2019, to stockholders
of record at the close of business on May 13,
2019.
On July 11, 2019, we announced a quarterly dividend of
$0.305 per share.
The dividend was paid on September 3, 2019, to
stockholders of record at the close of
business on July 22, 2019.
On October 7, 2019, we announced a 38 percent increase
in the quarterly dividend
to $0.42 per share.
The dividend was paid on December 2, 2019, to
stockholders of record at the close of
business on October 17, 2019.
In February 2020, we announced a quarterly dividend
of $0.42 per share,
payable March 2, 2020, to stockholders of record
at the close of business on February 14, 2020.
In late 2016, we initiated our current share repurchase
program.
As of December 31, 2019, we had announced
a total authorization to repurchase $15 billion
of our common stock.
We repurchased $3 billion in 2017, $3
billion in 2018 and $3.5 billion in 2019.
Of the remaining authorization, we expect to
repurchase $3 billion in
2020.
In February 2020, we announced that the
Board of Directors approved an increase to
our authorization
from $15 billion to $25 billion, to support our
plan for future share repurchases.
Whether we undertake these
additional repurchases is ultimately subject to numerous
considerations, market conditions and other factors.
See Risk Factors -“Our ability to declare and pay
dividends and repurchase shares is subject to certain
considerations.”
Since our share repurchase program began
in November 2016, we have repurchased 169
million shares at a cost of $9.6 billion through
December 31, 2019.
Contractual Obligations
The table below summarizes our aggregate contractual
fixed and variable obligations as of December
31, 2019:
Millions of Dollars
Payments Due by Period
Up to 1
Years
Years
After
Total
Year
2-3
4-5
5 Years
Debt obligations (a)
$
14,175
1,018
12,534
Finance lease obligations (b)
Total debt
14,895
1,175
12,869
Interest on debt
11,339
1,671
1,603
7,209
Operating lease obligations (c)
1,050
Purchase obligations (d)
8,671
3,237
1,745
1,327
2,362
Other long-term liabilities
Pension and postretirement benefit
contributions (e)
1,375
-
Asset retirement obligations (f)
6,206
4,618
Accrued environmental costs (g)
Unrecognized tax benefits (h)
(h)
(h)
(h)
Total
$
43,789
6,124
5,823
4,546
27,296
(a)
Includes $204 million of net unamortized premiums,
discounts and debt issuance costs.
See Note 11-
Debt, in the Notes to Consolidated Financial Statements,
for additional information.
(b)
See Note 17-Non-Mineral Leases, in the Notes to
Consolidated Financial Statements, for
additional
information.
(c)
Includes $31 million of short-term leases that
are not recorded on our consolidated balance
sheet.
See
Note 17-Non-Mineral Leases, in the Notes to
Consolidated Financial Statements, for
additional
information.
(d)
Represents any agreement to purchase goods
or services that is enforceable and legally binding
and that
specifies all significant terms, presented on an undiscounted
basis.
Does not include purchase
commitments for jointly owned fields and facilities
where we are not the operator.
The majority of the purchase obligations are market-based
contracts related to our commodity business.
Product purchase commitments with third parties
totaled $2,426 million.
Purchase obligations of $5,111 million are related to agreements to access and
utilize the capacity of
third-party equipment and facilities, including
pipelines and LNG and product terminals, to
transport,
process, treat and store commodities.
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.
(e)
Represents contributions to qualified and nonqualified
pension and postretirement benefit plans
for the
years 2020 through 2024.
For additional information related to expected
benefit payments subsequent to
2024, see Note 18-Employee Benefit Plans,
in the Notes to Consolidated Financial
Statements.
(f)
Represents estimated discounted costs to retire
and remove long-lived assets at the end of their
operations.
(g)
Represents estimated costs for accrued environmental
expenditures presented on a discounted basis
for
costs acquired in various business combinations
and an undiscounted basis for all other accrued
environmental costs.
(h)
Excludes unrecognized tax benefits of $1,095
million because the ultimate disposition and timing
of any
payments to be made with regard to such amounts
are not reasonably estimable.
Although unrecognized
tax benefits are not a contractual obligation,
they are presented in this table because they
represent
potential demands on our liquidity.
Capital Expenditures and Investments
Millions of Dollars
Alaska
$
1,513
1,298
Lower 48
3,394
3,184
2,136
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Capital Program
$
6,636
6,750
4,591
Our capital expenditures and investments
for the three-year period ended December 31,
2019, totaled $18.0
billion.
The 2019 expenditures supported key exploration
and developments, primarily:
●
Development, appraisal and exploration activities
in the Lower 48, including Eagle Ford, Permian
Unconventional, and Bakken.
●
Appraisal and development activities
in Alaska related to the Western North Slope; development
activities in the Greater Kuparuk Area and the
Greater Prudhoe Area; leasehold acquisition
in the
Greater Kuparuk Area.
●
Development activities across assets in Norway, as well as for assets in the U.K. that
recently have
been sold.
●
Optimization of oil sands development and appraisal
activities in liquids-rich plays in Canada.
●
Signature bonus for Indonesia Corridor Block
production sharing contract, as well as continued
development in China, Malaysia, Australia, and
Indonesia.
2020 CAPITAL BUDGET
In February 2020, we announced 2020 operating
plan capital of $6.5 billion to $6.7 billion.
The plan includes
funding for ongoing development drilling
programs, major projects, exploration and appraisal
activities, as
well as base maintenance.
Capital spend is expected to be higher in the first
quarter largely from winter
construction and exploration and appraisal drilling
in Alaska.
This guidance does not include capital for
acquisitions.
For information on PUDs and the associated costs
to develop these reserves, see the “Oil and
Gas Operations”
section in this report.
Contingencies
A number of lawsuits involving a variety of claims
arising in the ordinary course of business
have been filed
against ConocoPhillips.
We also may be required to remove or mitigate the effects on the environment of the
placement, storage, disposal or release of certain
chemical, mineral and petroleum substances
at various active
and inactive sites.
We regularly assess the need for accounting recognition or disclosure of these
contingencies.
In the case of all known contingencies (other
than those related to income taxes), we accrue
a
liability when the loss is probable and the amount
is reasonably estimable.
If a range of amounts can be
reasonably estimated and no amount within the range
is a better estimate than any other amount,
then the
minimum of the range is accrued.
We do not reduce these liabilities for potential insurance or third-party
recoveries.
If applicable, we accrue receivables for probable
insurance or other third-party recoveries.
With
respect to income tax-related contingencies,
we use a cumulative probability-weighted loss
accrual in cases
where sustaining a tax position is less than certain.
Based on currently available information, we believe
it is remote that future costs related to known
contingent
liability exposures will exceed current accruals by
an amount that would have a material
adverse impact on our
consolidated financial statements.
For information on other contingencies, see
“Critical Accounting
Estimates” and Note 13-Contingencies and
Commitments, in the Notes to Consolidated
Financial Statements.
Legal and Tax Matters
We are subject to various lawsuits and claims including but not limited to matters
involving oil and gas royalty
and severance tax payments, gas measurement and
valuation methods, contract disputes,
environmental
damages, climate change, personal injury, and property damage.
Our primary exposures for such matters
relate to alleged royalty and tax underpayments
on certain federal, state and privately owned
properties and
claims of alleged environmental contamination
from historic operations.
We will continue to defend ourselves
vigorously in these matters.
Our legal organization applies its knowledge, experience
and professional judgment to the specific
characteristics of our cases, employing a litigation
management process to manage and monitor the
legal
proceedings against us.
Our process facilitates the early evaluation and
quantification of potential exposures in
individual cases.
This process also enables us to track those cases that
have been scheduled for trial and/or
mediation.
Based on professional judgment and experience
in using these litigation management tools and
available information about current developments
in all our cases, our legal organization regularly assesses
the
adequacy of current accruals and determines if
adjustment of existing accruals, or establishment
of new
accruals, is required.
See Note 19-Income Taxes, in the Notes to Consolidated Financial Statements,
for
additional information about income tax-related
contingencies.
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.
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 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, 2019, there were 15 sites around
the U.S. in which we were identified as a potentially
responsible party under CERCLA and comparable
state laws.
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 $511 million in 2019 and are expected
to be about $545 million per year
in 2020 and 2021.
Capitalized environmental costs were $194 million
in 2019 and are expected to be about
$225 million per year in 2020 and 2021.
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, 2019, our balance sheet included
total accrued environmental costs of
$171 million,
compared with $178 million at December 31,
2018, for remediation activities in the
U.S. and Canada.
We
expect to incur a substantial amount of these expenditures
within the next 30 years.
Notwithstanding any of the foregoing, and as
with other companies engaged in similar businesses,
environmental costs and liabilities are inherent
concerns in our operations and products, and there
can be no
assurance that material costs and liabilities
will not be incurred.
However, we currently do not expect any
material adverse effect upon our results of operations or financial
position as a result of compliance with
current environmental laws and regulations.
Climate Change
Continuing political and social attention to the
issue of global climate change has resulted in
a broad range of
proposed or promulgated state, national and international
laws focusing on GHG reduction.
These proposed or
promulgated laws apply or could apply in countries
where we have interests or may have interests
in the future.
Laws in this field continue to evolve, and
while it is not possible to accurately estimate either
a timetable for
implementation or our future compliance costs
relating to implementation, such laws, if
enacted, could have a
material impact on our results of operations and
financial condition.
Examples of legislation or 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 2019
was
approximately $8 million before-tax.
●
The Alberta Carbon Competitiveness Incentive
Regulation (CCIR) requires any existing facility
with
emissions equal to or greater than 100,000 metric
tonnes of carbon dioxide, or equivalent,
per year to
meet an industry benchmark intensity.
The total cost of these regulations in 2019
was approximately
$4 million.
●
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 former U.S. administration established
a goal of reducing the 2012 levels in methane
emissions from the oil and gas industry by 40
to 45 percent by 2025.
●
Carbon taxes in certain jurisdictions.
Our cost of compliance with Norwegian carbon
tax legislation
in 2019 was approximately $30 million (net
share before-tax).
We also incur a carbon tax for
emissions from fossil fuel combustion in our
British Columbia and Alberta Operations
totaling just
over $0.8 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 on Climate Change, setting
out a new process for achieving global
emission
reductions.
While the U.S. announced its intention
to withdraw from the Paris Agreement, there
is no
guarantee that the commitments made by the
U.S. will not be implemented, in whole or
in part, by
U.S. state and local governments or by major corporations
headquartered in the U.S.
In 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.
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.
The company has responded by putting in place
a Sustainable Development Risk Management Standard
covering the assessment and registering of significant
and high sustainable development risks based
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 different scopes.
Scope 1 and Scope 2 GHG emissions
help us understand
climate transition risk.
Scope 1 emissions are direct GHG emissions from sources
that we own or control.
Scope 2 emissions are GHG emissions from
the generation of purchased electricity or
steam that we consume.
Our corporate authorization process requires all
qualifying projects to run a GHG pricing
sensitivity using a
corporate price of $40 per tonne of carbon
dioxide equivalent, plus annual inflation, for
all Scope 1 and Scope
2 GHG emissions produced in 2024 and later.
Projects in jurisdictions with existing GHG pricing
regimes
must incorporate that existing GHG price and its
forecast into their base case economics.
Where the existing
GHG price is below the corporate price, the
$40 per tonne of carbon dioxide equivalent
sensitivity must also be
run from 2024 onward.
Thus, 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.
In December 2018, we became a founding member
of the CLC, an international policy institute
founded in
collaboration with business and environmental
interests to develop a carbon dividend plan.
Participation in the
CLC provides another opportunity for ongoing
dialogue about carbon pricing and framing the
issues in
alignment with our public policy principles.
We also belong to and fund Americans For Carbon Dividends,
the education and advocacy branch of the CLC.
In 2017 and 2018, cities, counties, and a state
government in California, New York, Washington, Rhode Island
and Maryland, as well as the Pacific Coast Federation
of Fishermen’s Association, Inc., have filed lawsuits
against oil and gas companies, including ConocoPhillips,
seeking compensatory damages and equitable
relief
to abate alleged climate change impacts.
ConocoPhillips is vigorously defending against
these lawsuits.
The
lawsuits brought by the Cities of San Francisco,
Oakland and New York have been dismissed by the district
courts and appeals are pending.
Lawsuits filed by other cities and counties
in California and Washington are
currently stayed pending resolution of the appeals
brought by the Cities of San Francisco and
Oakland to the
U.S. Court of Appeals for the Ninth Circuit.
Lawsuits filed in Maryland and Rhode Island
are proceeding in
state court while rulings in those matters, on the
issue of whether the matters should proceed
in state or federal
court, are on appeal to the U.S. Court of Appeals
for the Fourth Circuit and First Circuit,
respectively.
Several Louisiana parishes and individual landowners
have filed lawsuits against oil and gas companies,
including ConocoPhillips, seeking compensatory
damages in connection with historical oil
and gas operations
in Louisiana.
All parish lawsuits are stayed pending an appeal
to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or
state court.
ConocoPhillips will vigorously defend against
these lawsuits.
Other
We have deferred tax assets related to certain accrued liabilities, loss carryforwards
and credit carryforwards.
Valuation
allowances have been established to reduce
these deferred tax assets to an amount that
will, more
likely than not, be realized.
Based on our historical taxable income, our expectations
for the future, and
available tax-planning strategies, management
expects the net deferred tax assets will be realized
as offsets to
reversing deferred tax liabilities.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in
conformity with GAAP requires management
to select appropriate
accounting policies and to make estimates
and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses.
See Note 1-Accounting Policies, in the Notes
to Consolidated Financial
Statements, for descriptions of our major accounting
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, along
with the discussion of
deferred tax asset valuation allowances in this
report, address all important accounting
areas where the nature
of accounting estimates or assumptions is material
due to the levels of subjectivity and judgment necessary
to
account for highly uncertain matters or the
susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas exploratory activity
is subject to special accounting rules unique
to the oil and gas
industry.
The acquisition of geological and geophysical
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
For individually significant leaseholds, management
periodically assesses for impairment based on
exploration
and drilling efforts to date.
For relatively small individual leasehold acquisition
costs, management exercises
judgment and determines a percentage probability
that the prospect ultimately will fail to find
proved oil and
gas reserves and pools that leasehold information
with others in the geographic area.
For prospects in areas
with limited, or no, previous exploratory drilling,
the percentage probability of ultimate failure
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.
At year-end 2019, the remaining $3.5 billion of net capitalized
unproved property costs consisted primarily
of
individually significant leaseholds, mineral rights
held in perpetuity by title ownership, exploratory
wells
currently being drilled, suspended exploratory
wells, and capitalized interest.
Of this amount, approximately
$2.1 billion is concentrated in 10 major development
areas, the majority of which are not expected to
move to
proved properties in 2020,
and $0.6 billion is held for sale.
Management periodically assesses individually
significant leaseholds for impairment based on
the results of exploration and drilling efforts and the outlook
for
commercialization.
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.
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.
For complex exploratory discoveries, it
is not unusual to have exploratory wells remain
suspended on the balance sheet for several
years while we perform additional appraisal
drilling and seismic
work on the potential oil and gas field or while
we seek government or co-venturer approval of development
plans or seek environmental permitting.
Once a determination is made the well did not
encounter potentially
economic oil and gas quantities, the well costs
are expensed as a dry hole and reported in
exploration expense.
Management reviews suspended well balances quarterly, continuously monitors
the results of the additional
appraisal drilling and seismic work, and expenses
the suspended well costs as a dry hole when
it determines
the potential field does not warrant further
investment in the near term.
Criteria utilized in making this
determination include evaluation of the reservoir
characteristics and hydrocarbon properties,
expected
development costs, ability to apply existing technology
to produce the reserves, fiscal terms,
regulations or
contract negotiations, and our expected return
on investment.
At year-end 2019,
total suspended well costs were $1,020 million,
compared with $856 million at year-end
2018.
For additional information on suspended wells,
including an aging analysis, see Note 8-Suspended
Wells and Other Exploration Expenses, in the Notes to Consolidated Financial
Statements.
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.
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 be permanently
shut down for
economic reasons is based on 12-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, 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 developed reserves also
is important to the income statement because the
proved
developed reserve estimate for a field serves as the
denominator in the unit-of-production
calculation of the
DD&A of the capitalized costs for that asset.
At year-end 2019, the net book value of productive PP&E
subject to a unit-of-production calculation was
approximately $35 billion and the DD&A recorded
on these
assets in 2019 was approximately $5.8 billion.
The estimated proved developed reserves for
our consolidated
operations were 3.3 billion BOE at the end
of 2018 and 3.2
billion BOE at the end of 2019.
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 2019
would have increased by an estimated $642
million.
Impairments
Long-lived assets used in operations are assessed
for impairment whenever changes in facts
and circumstances
indicate a possible significant deterioration
in future cash flows expected to be generated
by an asset group and
annually in the fourth quarter following updates
to corporate planning assumptions.
If there is an indication
the carrying amount of an asset may not be recovered,
the asset is monitored by management through
an
established process where changes to significant
assumptions such as prices, volumes and future
development
plans are reviewed.
If, upon review, the sum of the undiscounted before-tax cash flows is
less than the
carrying value of the asset group, the carrying
value is written down to estimated fair
value.
Individual assets
are grouped for impairment purposes based on a
judgmental assessment of 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 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 judgmental assessments of future production
volumes, commodity prices, operating
costs and capital
decisions, considering all available information
at the date of review.
Differing assumptions could affect the
timing and the amount of an impairment
in any period.
See Note 9-Impairments, in the Notes to
Consolidated Financial Statements, for additional
information.
Investments in nonconsolidated entities
accounted for under the equity method are reviewed
for impairment
when there is evidence of a loss in value and annually
following updates to corporate planning assumptions.
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 it is determined such a loss in value
is 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 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 6-Investments,
Loans and Long-Term Receivables,
in the Notes to Consolidated Financial Statements,
for additional
information.
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations,
we have material legal obligations to remove
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.
The fair values
of obligations for dismantling and removing these
facilities are recorded as a liability and
an increase to PP&E
at the time of installation of the asset based on estimated
discounted costs.
Estimating future asset removal
costs is difficult.
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.
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, are also subject to change.
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
10-Asset Retirement Obligations and Accrued
Environmental Costs, in the Notes to Consolidated
Financial
Statements, for additional information.
Projected Benefit Obligations
Determination of the projected benefit obligations
for our defined benefit pension and postretirement
plans are
important to the recorded amounts for such obligations
on the balance sheet and to the amount of benefit
expense in the income statement.
The actuarial determination of projected benefit
obligations and company
contribution requirements involves judgment about
uncertain future events, including estimated
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.
For Employee Retirement Income Security Act-
governed pension plans, the actuary exercises fiduciary
care on behalf of plan participants in the
determination
of the judgmental assumptions used in determining
required company contributions into the
plans.
Due to
differing objectives and requirements between financial
accounting rules and the pension plan funding
regulations promulgated by governmental agencies,
the actuarial methods and assumptions
for the two
purposes differ in certain important respects.
Ultimately, we will be required to fund all vested benefits under
pension and postretirement benefit plans not
funded by plan assets or investment returns,
but the judgmental
assumptions used in the actuarial calculations
significantly affect periodic financial statements and funding
patterns over time.
Projected benefit obligations are particularly
sensitive to the discount rate assumption.
A
100 basis-point decrease in the discount rate assumption
would increase projected benefit obligations
by
$1,000 million.
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
$100 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 18-Employee Benefit Plans, in the
Notes to Consolidated Financial Statements,
for additional
information.
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 Note 13-Contingencies
and Commitments.
CAUTIONARY STATEMENT
FOR THE PURPOSES OF THE “SAFE HARBOR”
PROVISIONS OF
THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements
within the meaning of Section 27A of the Securities
Act of
1933 and Section 21E of the Securities Exchange
Act of 1934.
All statements other than statements of
historical fact included or incorporated by reference in
this report, including, without limitation,
statements
regarding our future financial position, business
strategy, budgets, projected revenues, projected costs and
plans, and objectives of management for future operations,
are forward-looking statements.
Examples of
forward-looking statements contained in this report
include our expected production growth and
outlook on the
business environment generally, our expected capital budget and capital expenditures,
and discussions
concerning future dividends.
You can often identify our forward-looking statements by the words “anticipate,”
“estimate,” “believe,” “budget,” “continue,” “could,”
“intend,” “may,” “plan,” “potential,” “predict,” “seek,”
“should,” “will,” “would,” “expect,” “objective,”
“projection,” “forecast,” “goal,” “guidance,” “outlook,”
“effort,” “target” and similar expressions.
We based the forward-looking statements on our current expectations, estimates
and projections about
ourselves and the industries in which we operate in
general.
We caution you these statements are not
guarantees of future performance as they involve
assumptions that, while made in good faith,
may prove to be
incorrect, and involve risks and uncertainties
we cannot predict.
In addition, we based many of these forward-
looking statements on assumptions about future events
that may prove to be inaccurate.
Accordingly, our
actual outcomes and results may differ materially from
what we have expressed or forecast in the forward-
looking statements.
Any differences could result from a variety of factors,
including, but not limited to, the
following:
●
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 costs
on our long-lived assets, leaseholds and
nonconsolidated equity investments.
●
Potential failures or delays in achieving expected
reserve or production levels from existing
and future
oil and gas developments, including due to operating
hazards, drilling risks and the inherent
uncertainties in predicting reserves and reservoir
performance.
●
Reductions in reserves
replacement rates, whether as a result
of the significant declines in commodity
prices or otherwise.
●
Unsuccessful exploratory drilling activities
or the inability to obtain access to exploratory acreage.
●
Unexpected changes in costs or technical requirements
for constructing, modifying or operating E&P
facilities.
●
Legislative and regulatory initiatives
addressing environmental concerns, including initiatives
addressing the impact of global climate change or further
regulating hydraulic fracturing, methane
emissions, flaring or water disposal.
●
Lack of, or disruptions in, adequate and reliable
transportation for our crude oil, bitumen, natural
gas,
LNG and NGLs.
●
Inability to timely obtain or maintain permits,
including those necessary for construction, drilling
and/or development, or inability to make capital
expenditures required to maintain compliance
with
any necessary permits or applicable laws or regulations.
●
Failure to complete definitive agreements and feasibility
studies for, and to complete construction of,
announced and future exploration and production
and LNG development in a timely manner
(if at all)
or on budget.
●
Potential disruption or interruption of our operations
due to accidents, extraordinary weather
events,
civil unrest, political events, war, global health epidemics, 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
or future
environmental regulations and litigation.
●
Significant operational or investment changes imposed
by existing or future environmental
statutes
and regulations, including international agreements
and national or regional legislation and regulatory
measures to limit or reduce GHG emissions.
●
Liability resulting from litigation or our failure
to comply with applicable laws and regulations.
●
General domestic and international economic and
political developments, including armed
hostilities;
expropriation of assets; changes in governmental
policies relating to crude oil, bitumen, natural
gas,
LNG and NGLs pricing, regulation or taxation;
the impact of and uncertainty surrounding the
U.K.’s
decision to withdraw from the EU; 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, including changes
resulting from the implementation and interpretation
of
the Tax Cuts and Jobs Act.
●
Competition and consolidation in the oil and gas
E&P industry.
●
Any limitations on our access to capital or increase
in our cost of capital, including as a result
of
illiquidity or uncertainty in domestic or international
financial markets.
●
Our inability to execute, or delays in the completion,
of any asset dispositions or acquisitions
we elect
to pursue.
●
Potential failure to obtain, or delays in obtaining,
any necessary regulatory approvals for
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 asset dispositions or acquisitions, including
the
diversion
of management time and attention.
●
Our inability to deploy the net proceeds from any
asset dispositions we undertake in the manner
and
timeframe we currently anticipate, if at all.
●
Our inability to liquidate the common stock issued
to us by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem
acceptable, or at all.
●
The operation and financing of our joint ventures.
●
The ability of our customers and other contractual
counterparties to satisfy their obligations to
us,
including our ability to collect payments
when due from the government of Venezuela or PDVSA.
●
Our inability to realize anticipated cost savings
and expenditure reductions.
●
The factors generally described in Item 1A - Risk
Factors in this 2019 Annual Report on Form 10-K
and any additional risks described in our other filings
with the SEC.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk
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, 2019,
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, 2019 and 2018,
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.
The fair value of the fixed-rate debt is
measured using prices available from a pricing
service that is corroborated by market
data.
Millions of Dollars Except as Indicated
Debt
Fixed
Average
Floating
Average
Rate
Interest
Rate
Interest
Expected Maturity Date
Maturity
Rate
Maturity
Rate
Year
-End 2019
$
-
-
%
$
-
-
%
6.24
-
-
2.54
2.81
7.20
-
-
3.52
-
-
Remaining years
12,143
6.25
1.65
Total
$
13,188
$
Fair value
$
17,325
$
Year
-End 2018
$
-
%
$
-
-
%
-
-
-
-
9.13
-
-
2.54
3.52
7.20
-
-
Remaining years
12,599
6.16
1.78
Total
$
13,188
$
Fair value
$
15,364
$
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, 2019 and 2018, we held foreign
currency exchange forwards hedging cross-border
commercial activity and foreign currency exchange
swaps and options for purposes of mitigating
our cash-
related exposures.
Although these forwards, swaps and options
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, 2019,
we had outstanding foreign currency exchange
forward contracts to sell $1.35 billion
CAD at $0.748 CAD against the U.S. dollar.
At December 31, 2018, we had outstanding foreign
currency
zero-cost collars buying the right to sell $1.25 billion
CAD at $0.707
CAD and selling the right to buy $1.25
billion CAD at $0.842 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, 2019 and
December 31,
2018, was a before-tax loss of $28 million and a before-tax
gain of $6
million, respectively.
Based on an
adverse hypothetical 10 percent change in the
December 2019 and December 2018 exchange rate, this
would
result in an additional before-tax loss of $115 million and $17 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.
The gross notional and fair value of these positions
at December 31, 2019 and 2018, were as follows:
In Millions
Foreign Currency Exchange Derivatives
Notional*
Fair Value**
Sell U.S. dollar, buy British pound
USD
-
-
(5)
Sell Canadian dollar, buy U.S. dollar
CAD
1,350
1,250
(28)
Buy Canadian dollar, sell U.S. dollar
CAD
-
-
Sell British pound, buy Norwegian krone
GBP
-
-
-
Sell British pound, buy euro
GBP
-
-
-
Buy British pound, sell euro
GBP
-
-
-
*Denominated in USD, CAD and GBP.
**Denominated in USD.
For additional information about our use of derivative
instruments, see Note 14-Derivative and Financial
Instruments, in the Notes to Consolidated Financial
Statements.

Item 8. Financial Statements and Supplementary Data
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA
CONOCOPHILLIPS
Page
Report of Management ............................................................................................................................
Reports of Independent Registered Public Accounting
Firm .................................................................
Consolidated Income Statement for the years ended
December 31, 2019,
2018 and 2017
....................
Consolidated Statement of Comprehensive Income
for the years ended
December 31, 2019, 2018 and 2017
..................................................................................................
Consolidated Balance Sheet at December 31, 2019
and 2018
................................................................
Consolidated Statement of Cash Flows for the years
ended December 31, 2019,
2018 and 2017
.........
Consolidated Statement of Changes in Equity for
the years ended
December 31, 2019, 2018 and 2017
..................................................................................................
Notes to Consolidated Financial Statements
............................................................................................
Supplementary Information
Oil and Gas Operations
..............................................................................................................
Selected Quarterly Financial Data
..............................................................................................
Condensed Consolidating Financial Information
.......................................................................
Report 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
presentation 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, 2019.
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, 2019.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2019, and their report is included
herein.
/s/ Ryan M. Lance
/s/ Don E. Wallette, Jr.
Ryan M. Lance
Don E. Wallette, Jr.
Chairman and
Chief Executive Officer
Executive Vice President and
Chief Financial Officer
February 18, 2020
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, 2019 and 2018, 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, 2019, and the related notes, condensed
consolidating financial information listed in
the Index at
Item 8, and financial statement schedule listed
in Item 15(a) (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
at December 31, 2019 and 2018, and the
results of its
operations and its cash flows for each of the three
years in the period ended December 31, 2019,
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, 2019,
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 18, 2020,
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.
Accounting for asset retirement obligations
for certain offshore properties
Description of
the Matter
At December 31, 2019, the asset retirement
obligation (“ARO”) balance totaled $6.2
billion. As further described in Note 10, 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 of these removal
costs and higher estimation uncertainty
related to the removal plan and 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 remaining 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.
We involved our internal specialists in testing the underlying removal cost
estimates.
Depreciation, depletion and amortization of
proved oil and gas properties
Description of
the Matter
At December 31, 2019, the net book value of
the Company’s properties, plants and
equipment was $42.3 billion, and depreciation,
depletion and amortization (DD&A)
expense was $6.1 billion for the year then ended.
As described in Note 1, DD&A of
properties, plants and equipment on producing
hydrocarbon properties and certain
pipeline and LNG assets (those which are expected
to have a declining utilization
pattern) are determined by the unit-of-production method
based on 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
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 oil and gas reserves,
management also used a third-party petroleum
engineering 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.
Auditing the Company’s DD&A calculation is complex because of the
use of the work of
the internal reservoir engineers and third-party petroleum
engineering 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 process 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 reserve estimates
and the third-party petroleum
engineering 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. For proved undeveloped reserves,
we evaluated management’s
development plan for compliance with the SEC
rule that undrilled locations are
scheduled to be drilled within five years, unless
specific circumstances justify a longer
time, by assessing consistency of the development
projections with the Company’s drill
plan. We also tested the accuracy of the DD&A calculations, including comparing the
proved oil and gas reserve amounts used in the
calculation to the Company’s reserve
report.
/s/ Ernst & Young LLP
We have served as ConocoPhillips’ auditor since 1949.
Houston, Texas
February 18, 2020
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,
2019, 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, 2019,
based on the COSO criteria.
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, 2019 and 2018, 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, 2019, and the related notes,
condensed consolidating
financial information listed in the Index at Item 8, and financial statement schedule
listed in Item 15(a) and our
report dated February 18, 2020, 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
“Report 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.
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 18, 2020
Consolidated Income Statement
ConocoPhillips
Years
Ended December 31
Millions of Dollars
Revenues and Other Income
Sales and other operating revenues
$
32,567
36,417
29,106
Equity in earnings of affiliates
1,074
Gain on dispositions
1,966
1,063
2,177
Other income
1,358
Total Revenues and
Other Income
36,670
38,727
32,584
Costs and Expenses
Purchased commodities
11,842
14,294
12,475
Production and operating expenses
5,322
5,213
5,162
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
6,090
5,956
6,845
Impairments
6,601
Taxes other than income
taxes
1,048
Accretion on discounted liabilities
Interest and debt expense
1,098
Foreign currency transaction (gains) losses
(17)
Other expenses
Total Costs and Expenses
27,146
28,754
35,199
Income (loss) before income taxes
9,524
9,973
(2,615)
Income tax provision (benefit)
2,267
3,668
(1,822)
Net income (loss)
7,257
6,305
(793)
Less: net income attributable to noncontrolling interests
(68)
(48)
(62)
Net Income (Loss) Attributable to ConocoPhillips
$
7,189
6,257
(855)
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
6.43
5.36
(0.70)
Diluted
6.40
5.32
(0.70)
Average Common
Shares Outstanding
(in thousands)
Basic
1,117,260
1,166,499
1,221,038
Diluted
1,123,536
1,175,538
1,221,038
See Notes to Consolidated Financial Statements.
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years
Ended December 31
Millions of Dollars
Net Income (Loss)
$
7,257
6,305
(793)
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period
-
(7)
Reclassification adjustment for amortization of prior
service credit included in net income (loss)
(35)
(40)
(38)
Net change
(35)
(47)
(36)
Net actuarial gain (loss) arising during the period
(55)
(150)
Reclassification adjustment for amortization of net
actuarial losses included in net income (loss)
Net change
Nonsponsored plans*
(3)
(1)
(2)
Income taxes on defined benefit plans
(2)
(42)
(81)
Defined benefit plans, net of tax
Unrealized holding loss on securities
-
-
(58)
Unrealized loss on securities, net of tax
-
-
(58)
Foreign currency translation adjustments
(645)
Income taxes on foreign currency translation adjustments
(4)
-
Foreign currency translation adjustments, net of tax
(642)
Other Comprehensive Income (Loss), Net of
Tax
(603)
Comprehensive Income (Loss)
8,003
5,702
(118)
Less: comprehensive income attributable to noncontrolling interests
(68)
(48)
(62)
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
7,935
5,654
(180)
*Plans for which ConocoPhillips is not the primary obligor
-
primarily those administered by equity affiliates.
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheet
ConocoPhillips
At December 31
Millions of Dollars
Assets
Cash and cash equivalents
$
5,088
5,915
Short-term investments
3,028
Accounts and notes receivable (net of allowance of $
million in 2019
and $
million in 2018)
3,267
3,920
Accounts and notes receivable-related parties
Investment in Cenovus Energy
2,111
1,462
Inventories
1,026
1,007
Prepaid expenses and other current assets
2,259
Total Current Assets
16,913
13,274
Investments and long-term receivables
8,687
9,329
Loans and advances-related parties
Net properties, plants and equipment (net of accumulated depreciation,
depletion
and amortization of $
55,477
million in 2019 and $
64,899
million in 2018)
42,269
45,698
Other assets
2,426
1,344
Total Assets
$
70,514
69,980
Liabilities
Accounts payable
$
3,176
3,863
Accounts payable-related parties
Short-term debt
Accrued income and other taxes
1,030
1,320
Employee benefit obligations
Other accruals
2,045
1,259
Total Current Liabilities
7,043
7,395
Long-term debt
14,790
14,856
Asset retirement obligations and accrued environmental costs
5,352
7,688
Deferred income taxes
4,634
5,021
Employee benefit obligations
1,781
1,764
Other liabilities and deferred credits
1,864
1,192
Total Liabilities
35,464
37,916
Equity
Common stock (
2,500,000,000
shares authorized at $
0.01
par value)
Issued (2019-
1,795,652,203
shares; 2018-
1,791,637,434
shares)
Par value
Capital in excess of par
46,983
46,879
Treasury stock (at cost: 2019-
710,783,814
shares; 2018-
653,288,213
shares)
(46,405)
(42,905)
Accumulated other comprehensive loss
(5,357)
(6,063)
Retained earnings
39,742
34,010
Total Common
Stockholders’ Equity
34,981
31,939
Noncontrolling interests
Total Equity
35,050
32,064
Total Liabilities and Equity
$
70,514
69,980
See Notes to Consolidated Financial Statements.
Consolidated Statement of Cash Flows
ConocoPhillips
Years
Ended December 31
Millions of Dollars
Cash Flows From Operating Activities
Net income (loss)
$
7,257
6,305
(793)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation, depletion and amortization
6,090
5,956
6,845
Impairments
6,601
Dry hole costs and leasehold impairments
Accretion on discounted liabilities
Deferred taxes
(444)
(3,681)
Undistributed equity earnings
(232)
Gain on dispositions
(1,966)
(1,063)
(2,177)
Other
(1,000)
(429)
Working
capital adjustments
Decrease (increase) in accounts and notes receivable
(886)
Decrease (increase) in inventories
(67)
(55)
Decrease (increase) in prepaid expenses and other current assets
(55)
Increase (decrease) in accounts payable
(378)
(52)
Increase (decrease) in taxes and other accruals
(676)
Net Cash Provided by Operating Activities
11,104
12,934
7,077
Cash Flows From Investing Activities
Capital expenditures and investments
(6,636)
(6,750)
(4,591)
Working
capital changes associated with investing activities
(103)
(68)
Proceeds from asset dispositions
3,012
1,082
13,860
Net sales (purchases) of investments
(2,910)
1,620
(1,790)
Collection of advances/loans-related parties
Other
(108)
Net Cash Provided by (Used in) Investing Activities
(6,618)
(3,843)
7,762
Cash Flows From Financing Activities
Repayment of debt
(80)
(4,995)
(7,876)
Issuance of company common stock
(30)
(63)
Repurchase of company common stock
(3,500)
(2,999)
(3,000)
Dividends paid
(1,500)
(1,363)
(1,305)
Other
(119)
(123)
(112)
Net Cash Used in Financing Activities
(5,229)
(9,359)
(12,356)
Effect of Exchange Rate Changes on Cash, Cash Equivalents
and Restricted Cash
(46)
(117)
Net Change in Cash, Cash Equivalents and Restricted Cash
(789)
(385)
2,715
Cash, cash equivalents and restricted cash at beginning of period
6,151
6,536
3,610
Cash, Cash Equivalents and Restricted Cash at End of Period
$
5,362
6,151
6,325
Restricted cash of $
million and $
million are included in the “Prepaid expenses and other current assets” and “Other assets” lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2019.
Restricted cash totaling $
million is included in the “Other assets” line of our Consolidated
Balance Sheet as of December 31, 2018.
See Notes to Consolidated Financial Statements.
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
December 31, 2016
$
46,507
(36,906)
(6,193)
31,548
35,226
Net income (loss)
(855)
(793)
Other comprehensive income
Dividends paid ($
1.06
per share of common stock)
(1,305)
(1,305)
Repurchase of company common stock
(3,000)
(3,000)
Distributions to noncontrolling interests and other
(120)
(120)
Distributed under benefit plans
Other
December 31, 2017
$
46,622
(39,906)
(5,518)
29,391
30,801
Net income
6,257
6,305
Other comprehensive loss
(603)
(603)
Dividends paid ($
1.16
per share of common stock)
(1,363)
(1,363)
Repurchase of company common stock
(2,999)
(2,999)
Distributions to noncontrolling interests and other
(121)
(121)
Distributed under benefit plans
Changes in Accounting Principles*
(278)
(220)
Other
December 31, 2018
$
46,879
(42,905)
(6,063)
34,010
32,064
Net income
7,189
7,257
Other comprehensive income
Dividends paid ($
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
Changes in Accounting Principles**
(40)
-
Other
December 31, 2019
$
46,983
(46,405)
(5,357)
39,742
35,050
*Cumulative effect of the adoption of ASC Topic 606, "Revenue from Contracts with Customers," and ASU No.
2016-01, "Recognition and
Measurement of Financial Assets and Liabilities," at January 1, 2018.
**See Note 2-Changes in Accounting Principles for additional
information.
See Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1-Accounting Policies
■
Consolidation Principles and Investments
-Our consolidated financial statements
include the accounts
of majority-owned, controlled subsidiaries
and 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 and North Africa, Asia Pacific
and Middle East, and Other International.
For
additional information, see Note 25-Segment
Disclosures and Related Information.
■
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 accounting principles
generally accepted in the U.S. 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.
■
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.
■
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
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 8-
Suspended Wells and Other Exploration Expenses, for additional information
on suspended wells.
Development Costs
-Costs incurred to drill and equip development
wells, including unsuccessful
development wells, are capitalized.
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 intangible
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 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
-PP&E 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 and annually in the fourth
quarter
following updates to corporate planning assumptions.
If there is an indication the carrying amount of
an
asset may not be recovered, the asset is monitored
by management through an established
process where
changes to significant assumptions such as prices,
volumes and future development plans are reviewed.
If, upon review, the sum of the undiscounted before-tax cash flows is less
than the carrying value of the
asset group, the carrying value is written down to
estimated fair value through additional
amortization or
depreciation provisions and reported as impairments
in the periods in which the determination
of the
impairment 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
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.
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.
The expected future cash flows used for impairment
reviews and related fair value calculations are
based
on estimated future production volumes, prices
and costs, 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.
■
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 and annually following updates to corporate
planning assumptions.
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 believed to be consistent
with
those used by principal market participants,
plus market analysis of comparable assets
owned by the
investee, if appropriate.
■
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 less than complete 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).
When the liability is initially recorded,
we
capitalize this 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 is increased for the change in its present
value, and the capitalized cost in PP&E is
depreciated 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.
For additional information, see
Note 10-Asset Retirement Obligations and Accrued
Environmental Costs.
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 in a purchase
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.
■
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.
■
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-Changes in Accounting Principles
We adopted the provisions of FASB ASU No. 2016-02, “Leases,” (ASC Topic 842) and its amendments,
beginning January 1, 2019.
ASC Topic 842 establishes comprehensive accounting and financial reporting
requirements for leasing arrangements, supersedes
the existing requirements in FASB ASC Topic 840,
“Leases” (ASC Topic 840), and requires lessees to recognize substantially
all lease assets and lease liabilities
on the balance sheet.
The provisions of ASC Topic 842 also modify the definition of a lease
and outline
requirements for recognition, measurement, presentation
and disclosure of leasing arrangements by
both
lessees and lessors.
We adopted ASC Topic
842 using the modified retrospective
approach and elected to utilize the Optional
Transition Method, which permits us to apply the provisions
of ASC Topic 842 to leasing arrangements
existing at or entered into after January 1, 2019,
and present in our financial statements comparative
periods
prior to January 1, 2019 under the historical
requirements of ASC Topic 840.
In addition, we elected to adopt
the package of optional transition-related practical
expedients, which among other things, allows us to
carry
forward certain historical conclusions reached
under ASC Topic 840 regarding lease identification,
classification, and the accounting treatment
of initial direct costs.
Furthermore, we elected not to record assets
and liabilities on our consolidated balance sheet
for new or existing lease arrangements
with terms of 12
months or less.
The primary impact of applying ASC Topic 842 is the initial recognition
of $
million of lease liabilities and
corresponding right-of-use assets on our consolidated
balance sheet as of January 1, 2019, for leases
classified
as operating leases under ASC Topic 840, as well as enhanced disclosure of our leasing
arrangements.
Our
accounting treatment for finance leases remains
unchanged.
In addition, there is no cumulative effect to
retained earnings or other components of equity
recognized as of January 1, 2019, and the adoption
of ASC
Topic 842 did not impact the presentation of our consolidated income statement
or statement of cash flows.
See Note 17-Non-Mineral Leases for additional
information related to the adoption of ASC Topic 842.
We adopted the provisions of FASB ASU No. 2018-02, “Reclassification of Certain Tax Effects from
Accumulated Other Comprehensive Income,”
beginning January 1, 2019.
The ASU allows a reclassification
from accumulated other comprehensive income
to retained earnings for stranded tax effects resulting
from the
Tax Cuts and Jobs Act, eliminating the stranded tax effects.
The cumulative effect to our consolidated balance
sheet at January 1, 2019 for the adoption of
ASU No. 2018-02 was as follows:
Millions of Dollars
December 31
ASU No. 2018-02
January 1
Adjustments
Equity
Accumulated other comprehensive loss
$
(6,063)
(40)
(6,103)
Retained earnings
34,010
34,050
For additional information regarding the impact of the adoption of ASU No. 2018-02, see
Note 20-Accumulated Other Comprehensive Loss.
Note 3-Variable Interest Entities
We hold variable interests in VIEs for which there are existing arrangements that provide
those entities with
additional forms of subordinated financial support.
However, as we are not considered the primary
beneficiary, these entities have not been consolidated in our financial statements.
Marine Well Containment Company, LLC (MWCC)
We have a
percent ownership interest in MWCC, and
it is accounted for as an equity method investment
because MWCC is a limited liability company
in which we are a founding member.
MWCC is considered a
VIE, as it has entered into arrangements that provide
it with additional forms of subordinated
financial support.
We are not the primary beneficiary and do not consolidate MWCC because we share
the power to govern the
business and operation of the company and to
undertake certain obligations that most
significantly impact its
economic performance with nine other unaffiliated
owners of MWCC.
Based on inputs related to the fair value of MWCC
observed in the second quarter of 2019, we reduced
the
carrying value of our equity method investment
in MWCC to $
million and recorded a before-tax
impairment of $
million which is included in the “Equity
in earnings of affiliates” line on our consolidated
income statement. For additional information
see Note 15-Fair Value Measurement.
At December 31, 2019,
the book value of our equity method investment
in MWCC was $
million. We have not provided any
financial support to MWCC other than amounts
previously contractually required. Unless we elect
otherwise,
we have no requirement to provide liquidity
or purchase the assets of MWCC.
Australia Pacific LNG Pty Ltd (APLNG)
We hold a
37.5
percent interest in APLNG, our joint venture
with Origin Energy and Sinopec. We are not the
primary beneficiary because we share, with
our joint venture partners, the power to direct
the key activities of
APLNG that most significantly impacts its
economic performance. Therefore, we do not consolidate
APLNG
and account for this entity as an equity method
investment.
As of December 31, 2019, we no longer have
certain guarantees that provide APLNG with additional
subordinated financial support. For additional
information see Note 12-Guarantees.
Note 4-Inventories
Inventories at December 31 were:
Millions of Dollars
Crude oil and natural gas
$
Materials and supplies
$
1,026
1,007
Inventories valued on the LIFO basis totaled
$
million and $
million at December 31, 2019 and 2018,
respectively.
The estimated excess of current replacement
cost over LIFO cost of inventories was
approximately $
million and $
million at December 31, 2019 and December
31, 2018, respectively.
Note 5-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
statement.
All cash proceeds are included in the “Cash Flows
From Investing Activities” section of our consolidated
statement of cash flows.
Assets Held for Sale
In October 2019, we entered into an agreement to sell
the subsidiaries that hold our Australia-West assets and
operations to Santos for $
1.39
billion, plus customary adjustments, with an effective
date of January 1, 2019.
In addition, we will receive a payment of $
million upon final investment decision of
the Barossa
development project.
These subsidiaries hold our
37.5
percent interest in the Barossa Project and
Caldita
Field, our
56.9
percent interest in the Darwin LNG Facility and
Bayu-Undan Field, our
percent interest in
the Greater Poseidon Fields, and our
percent interest in the Athena Field.
The net carrying value is
approximately $
0.6
billion, which consisted primarily of $
1.2
billion of PP&E and $
0.3
billion of cash and
working capital, offset by $
0.7
billion of ARO and $
0.2
billion of deferred tax liabilities.
The assets met held
for sale criteria in the fourth quarter, and as of December 31, 2019
we had reclassified $
1.2
billion of PP&E to
“Prepaid expenses and other current assets” and $
0.7
billion of noncurrent ARO to “Other accruals”
on our
consolidated balance sheet.
The before-tax earnings associated with our
Australia-West subsidiaries were
$
million, $
million and $
million for the years ended December 31,
2019, 2018 and 2017,
respectively.
This transaction is expected to be completed
in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent.
Results of operations for the subsidiaries
to be sold are
reported within our Asia Pacific and Middle East
segment.
In the fourth quarter of 2019, we signed an agreement
to sell our interests in the Niobrara shale play
for $
million, plus customary adjustments,
and overriding royalty interests in certain
future wells.
To reduce the
carrying value to fair value, in the fourth quarter
of 2019, we recorded an impairment of $
million before-
tax for developed properties and exploration expenses
of $
million related to leasehold impairment of
undeveloped properties.
Our Niobrara interests to be sold have a net carrying
value of approximately $
million, which consisted primarily of $
million of PP&E, offset by $
million of noncurrent ARO.
The
assets met held for sale criteria in the fourth quarter, and as of December
31, 2019, we had reclassified $
million of PP&E to “Prepaid expenses and other
current assets” and $
million of noncurrent AROs to “Other
accruals” on our consolidated balance sheet.
The before-tax losses associated with our interests
in Niobrara,
including the $386 million of impairments noted
above, were $
million and $
million for the years ended
December 31, 2019 and 2017,
respectively.
The before-tax earnings associated with our interests
in Niobrara
for the year ended December 31, 2018 was $
million.
This transaction is subject to regulatory approval
and
other specific conditions precedent and is expected
to close in the first quarter of 2020.
The Niobrara results of
operations are reported within our Lower 48 segment.
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 $
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 are reported in
our Lower 48 segment.
See Note 15-Fair Value
Measurement for additional information.
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 were $
0.4
billion, $
0.9
billion and $
0.3
billion for the years ended December 31, 2019,
and 2017,
respectively.
Results of operations for the U.K. are reported
within our Europe and North Africa
segment.
In the second quarter of 2019, we recognized an
after-tax gain of $
million upon the closing of the sale of
our
percent interest in the Greater Sunrise Fields
to the government of Timor-Leste for $
million.
The
Greater Sunrise Fields were included in our Asia
Pacific and Middle East segment.
In the fourth quarter of 2019, we sold our interests
in the Magnolia field and platform for net
proceeds of $
million and recognized a before-tax gain of $
million.
At the time of sale, the net carrying value consisted
of $
million of PP&E offset by $
million of ARO.
The Magnolia results of operations are reported
within
our Lower 48 segment.
Planned Dispositions
In January 2020, we entered into an agreement to sell
our interests in certain non-core properties
in the Lower
48 segment for $
million, plus customary adjustments.
The assets met the held for sale criteria in
January
2020 and the transaction is expected to be completed
in the first quarter of 2020.
No gain or loss is anticipated
on the sale.
This disposition will not have a significant
impact on Lower 48 production.
Assets Sold
In the first quarter of 2018, we completed the sale of
certain properties in the Lower 48 segment
for net
proceeds of $
million.
No
gain or loss was recognized on the sale.
In the second quarter of 2018, we
completed the sale of a package of largely undeveloped acreage
in the Lower 48 segment for net proceeds
of
$
million and
no
gain or loss was recognized on the sale.
In the third quarter of 2018, we completed a
noncash exchange of undeveloped acreage in
the Lower 48 segment.
The transaction was recorded at fair
value resulting in the recognition of a $
million gain.
In the fourth quarter of 2018, we sold several
packages of undeveloped acreage in the Lower
48 segment for total net proceeds of $
million and
recognized gains of approximately $
million.
On October 31, 2018, we completed the sale of
our interests in the Barnett to Lime Rock Resources
for $
million after customary adjustments and recognized
a loss of $
million. We recorded impairments of $
million in 2018 and $
million in 2017 to reduce the net
carrying value of the Barnett to fair value.
At the
time of the disposition, our interest in Barnett had a
net carrying value of $
million, consisting of $
million of PP&E and $
million of AROs.
The before-tax losses associated with our
interests in the Barnett,
including both the impairments and loss on disposition
noted above, were $
million and $
million for the
years 2018 and 2017, respectively.
The Barnett results of operations are included
in our Lower 48 segment.
On December 18, 2018, we completed the sale of
a ConocoPhillips subsidiary to BP.
The subsidiary held
16.5
percent of our 24 percent interest
in the BP-operated Clair Field in the U.K.
We retained a
7.5
percent
interest in the field.
At the same time, we acquired BP’s 39.2 percent nonoperated interest
in the Greater
Kuparuk Area in Alaska, including their 38 percent
interest in the Kuparuk Transportation Company (Kuparuk
Assets).
The transaction was recorded at a fair value
of $
1,743
million and was cash neutral except for
customary adjustments which resulted in net
proceeds of $
million.
At closing, our interest in the Clair
Field had a net carrying value of approximately
$
1,028
million consisting primarily of $
1,553
million of
PP&E, $
million of deferred tax liabilities, and $
million of AROs.
We recognized a before-tax gain of
$
million on the transaction.
The 2018 before-tax earnings associated
with our 16.5 interest in the Clair
Field, including the recognized gain, were $
million.
The before-tax loss associated with our interest
in the
Clair Field was $
0.4
million for 2017. Results of operations
for our interest in the Clair Field are reported
within our Europe and North Africa segment and
the Kuparuk Assets are included in our
Alaska segment.
Acquisitions
In May 2018, we completed the acquisition of
Anadarko’s
percent nonoperated interest in the Western
North Slope of Alaska, as well as its interest
in the Alpine Transportation Pipeline for $
million, after
customary adjustments.
This transaction was accounted for as a business
combination resulting in the
recognition of approximately $
million of proved property and $
million of unproved property within
PP&E, $
million of inventory, $
million of investments, and $
million of AROs. These assets are
included in our Alaska segment.
As discussed in the Clair Field transaction with BP
above, we acquired BP’s Kuparuk Assets on December 18,
2018.
The transaction was accounted for as an asset acquisition
with a net acquisition cost of $
1,490
million,
comprised of the fair value of $
1,743
million associated with the disposed 16.5
percent of our 24 percent
interest in the Clair Field, reduced by the net proceeds
of $253 million.
Accordingly, we recorded
approximately $
1.9
billion to proved property within PP&E, $
million to inventory, $
million to
investments, $
million of AROs, and a $
million decrease to net working capital.
The Kuparuk Assets
are included in our Alaska segment.
Assets Sold
On May 17, 2017, we completed the sale of our
50 percent nonoperated interest in the Foster
Creek Christina
Lake (FCCL) Partnership, as well as the majority
of our western Canada gas assets to Cenovus
Energy.
Consideration for the transaction was $
11.0
billion in cash after customary adjustments,
million Cenovus
Energy common shares and a five-year uncapped contingent
payment.
The value of the shares at closing was
$
1.96
billion based on a price of $
9.41
per share on the NYSE.
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.
Contingent payments received during the five-year
period are reflected as “Gain
on dispositions” on our consolidated income statement.
We reported before-tax equity earnings associated
with FCCL of $
million for 2017.
We reported a before-tax loss of $
million for the western Canada gas
producing properties for 2017.
We recorded gains on dispositions for these contingent payments of $
million and $
million for the years 2019 and 2018, respectively.
At closing, the carrying value of our equity investment
in FCCL was $
8.9
billion.
The carrying value of our
interest in the western Canada gas assets was $
1.9
billion consisting primarily of $
2.6
billion of PP&E, partly
offset by AROs of $
million and approximately $
million of environmental and other accruals.
A gain
of $
2.1
billion was included in the “Gain on dispositions”
line on our consolidated income statement in 2017.
Both FCCL and the western Canada gas assets
were reported in our Canada segment.
For more information on the Canada disposition
and our investment in Cenovus Energy see Note 7-
Investment in Cenovus Energy, Note 15-Fair Value Measurement, and Note 20-Accumulated Other
Comprehensive Loss.
In July 2017, we completed the sale of our interests
in the San Juan Basin to an affiliate of Hilcorp Energy
Company for $
2.5
billion in cash after customary adjustments
and recognized a loss on disposition of
$
million.
The transaction includes a contingent payment of up to $300 million. The six-year contingent
payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly U.S. Henry
Hub price is at or above $3.20 per MMBTU.
In 2018, we recorded a gain on dispositions
for these contingent
payments of $
million.
No
contingent payments were recorded in 2019.
In the second quarter of 2017, we
recorded an impairment of $
3.3
billion to reduce the carrying value of our
interests in the San Juan Basin to
fair value.
At the time of disposition, the San Juan Basin
interests had a net carrying value of approximately
$
2.5
billion, consisting of $
2.9
billion of PP&E and $
million of liabilities, primarily AROs.
The before-
tax loss associated with our interests in the San Juan
Basin, including both the $3.3 billion impairment
and $22
million loss on disposition noted above, was $
3.2
billion for 2017.
The San Juan Basin results were reported
in our Lower 48 segment.
In September 2017, we completed the sale of our
interest in the Panhandle assets for $
million in cash after
customary adjustments and recognized a loss on
disposition of $
million.
At the time of the disposition, the
carrying value of our interest was $
million, consisting primarily of $
million of PP&E and $
million
of AROs.
Including the $28 million loss on disposition
noted above, we reported a before-tax loss for the
Panhandle properties of $
million for 2017.
The Panhandle results were reported in
our Lower 48 segment.
Note 6-Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term
receivables at December 31 were:
Millions of Dollars
Equity investments
$
8,234
9,005
Loans and advances-related parties
Long-term receivables
Long-term investments in debt securities
-
Other investments
$
8,906
9,664
Equity Investments
Affiliated companies in which we had a significant
equity investment at December 31, 2019, included:
●
APLNG-
37.5
percent owned joint venture with Origin Energy (
37.5
percent) and Sinopec (
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 Qatar
Petroleum (
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
Revenues
$
11,310
11,654
11,554
Income (loss) before income taxes
3,726
3,660
(2,875)
Net income (loss)
3,085
3,244
(1,431)
Summarized 100 percent balance sheet information
for equity method investments in affiliated
companies,
combined, was as follows:
Millions of Dollars
Current assets
$
3,289
3,285
Noncurrent assets
38,905
41,563
Current liabilities
2,603
2,625
Noncurrent liabilities
22,168
23,874
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, 2019, retained earnings included
$
million related to the undistributed earnings
of
affiliated companies.
Dividends received from affiliates were $
1,378
million, $
1,226
million and $
million
in 2019, 2018 and 2017,
respectively.
APLNG
APLNG is focused on CBM production from the
Bowen and Surat basins in Queensland, Australia,
to supply
the domestic gas market and on LNG processing
and export sales.
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.
The $8.5
billion project finance facility was initially composed
of financing agreements executed by APLNG
with the
Export-Import Bank of the United States for approximately
$
2.9
billion, the Export-Import Bank of China for
approximately $
2.7
billion, and a syndicate of Australian and international
commercial banks for
approximately $
2.9
billion.
At December 31, 2019, all amounts have been
drawn from the facility.
APLNG
made its first principal and interest repayment
in March 2017 and is scheduled to make
bi-annual
payments
until March 2029.
APLNG made a voluntary repayment of $
1.4
billion to the Export-Import Bank of China
in September 2018.
At the same time, APLNG obtained a United
States Private Placement (USPP) bond facility
of $
1.4
billion.
APLNG made its first interest payment related to
this facility in March 2019, and principal
payments are
scheduled to commence in September 2023,
with
bi-annual
payments due on the facility until September
2030.
During the first quarter of 2019, APLNG refinanced
$
3.2
billion of existing project finance debt through two
transactions.
As a result of the first transaction, APLNG
obtained a commercial bank facility of $
2.6
billion.
APLNG made its first principal and interest
repayment in September 2019 with
bi-annual
payments due on the
facility until March 2028.
Through the second transaction, APLNG obtained
a USPP bond facility of $
0.6
billion.
APLNG made its first interest payment in September
2019, and principal payments are scheduled
to
commence in September 2023, with
bi-annual
payments due on the facility until
September 2030.
In conjunction with the $3.2 billion debt obtained
during the first quarter of 2019 to refinance existing
project
finance debt, APLNG made voluntary repayments
of $
2.2
billion and $
1.0
billion to a syndicate of Australian
and international commercial banks and the Export-Import
Bank of China, respectively.
At December 31, 2019, a balance of $
6.7
billion was outstanding on the facilities.
See Note 12-Guarantees,
for additional information.
During the first half of 2017, the outlook for crude
oil prices deteriorated, and as a result of significantly
reduced price outlooks, the estimated fair
value of our investment in APLNG declined to
an amount below
carrying value.
Based on a review of the facts and circumstances
surrounding this decline in fair value, we
concluded in the second quarter of 2017 the impairment
was other than temporary under the guidance of
FASB
ASC Topic 323, “Investments-Equity Method and Joint Ventures,” and the recognition of an impairment of
our investment to fair value was necessary.
Accordingly, we recorded a noncash $
2,384
million, before- and
after-tax impairment in our second quarter 2017
results.
Fair value was estimated based on an internal
discounted cash flow model using estimated
future production, an outlook of future prices
from a combination
of exchanges (short-term) and pricing service
companies (long-term), costs, a market
outlook of foreign
exchange rates provided by a third party, and a discount rate believed to be
consistent with those used by
principal market participants.
The impairment was included in the “Impairments”
line on our consolidated
income statement.
At December 31, 2019, the carrying value of
our equity method investment in APLNG was $
7,228
million.
The historical cost basis of our
37.5
percent share of net assets on the books
of APLNG was $
6,751
million,
resulting in a basis difference of $
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 exploration and production license areas
owned by APLNG, some of which are not currently
in
production.
Any future additional payments are expected
to be allocated in a similar manner.
Each
exploration license area will periodically be reviewed
for any indicators of potential impairment,
which, if
required, would result in acceleration of basis
difference amortization.
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 2019,
2018 and 2017 was after-tax
expense of $
million, $
million and $
million, respectively, representing the amortization of this basis
difference on currently producing licenses.
Distributions from APLNG commenced in
April 2018.
FCCL
FCCL Partnership, a Canadian upstream 50/50 general
partnership with Cenovus Energy Inc., produces
bitumen in the Athabasca oil sands in northeastern
Alberta and sells the bitumen blend.
Cenovus is the
operator and managing partner of FCCL.
On May 17, 2017, we completed the sale of our
50 percent nonoperated interest in the FCCL
Partnership, as
well as the majority of our western Canada gas
assets to Cenovus Energy.
Financial information presented
within this footnote includes our historical
interest up to the date of sale.
For additional information on the
Canada disposition and our investment in Cenovus
Energy, see Note 5-Asset Acquisitions and Dispositions
and Note 7-Investment in Cenovus Energy.
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 $
million as described below under “Loans and
Long-
Term Receivables.”
At December 31, 2019, the book value of our equity
method investment in QG3,
excluding the project financing, was $
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.
For additional information, see Note 5-Asset
Acquisitions and Dispositions.
Loans and Long-Term Receivables
As part of our normal ongoing business operations
and consistent with industry practice,
we enter into
numerous agreements with other parties to pursue
business opportunities.
Included in such activity are loans
and long-term receivables to certain affiliated and non-affiliated
companies.
Loans are recorded when cash is
transferred or seller financing is provided to the
affiliated or non-affiliated company pursuant to a loan
agreement.
The loan balance will increase as interest is earned
on the outstanding loan balance and will
decrease as interest and principal payments are
received.
Interest is earned at the loan agreement’s stated
interest rate.
Loans and long-term receivables are assessed
for impairment when events indicate the loan
balance may not be fully recovered.
At December 31, 2019, significant loans to affiliated
companies include $335 million in project financing
to
QG3.
We own a
percent interest in QG3, for which we
use the equity method of accounting.
The other
participants in the project are affiliates of Qatar Petroleum
and Mitsui.
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.
The long-term portion of these loans is included
in the “Loans and advances-related parties”
line on our
consolidated balance sheet, while the short-term
portion is in “Accounts and notes receivable-related
parties.”
Note 7-Investment in Cenovus Energy
On May 17, 2017, we completed the sale of our
percent nonoperated interest in the FCCL
Partnership, as
well as the majority of our western Canada gas
assets, to Cenovus Energy.
Consideration for the transaction
included
million Cenovus Energy common shares, which,
at closing, approximated
16.9
percent of issued
and outstanding Cenovus Energy common stock.
See Note 5-Asset Acquisitions and Dispositions,
for
additional information on the Canada disposition.
The fair value and cost basis of our investment
in 208
million Cenovus Energy common shares was $
1.96
billion based on a price of $
9.41
per share on the NYSE on
the closing date.
Our investment on our consolidated balance sheet
as of December 31, 2019, is carried
at fair value of $
2.11
billion, reflecting the closing price of Cenovus
Energy shares on the NYSE of $
10.15
per share, an increase of
$
million from $
1.46
billion at December 31, 2018.
The increase in fair value represents the
net unrealized
gain recorded within the “Other income” line of
our consolidated income statement for
the year ended
December 31, 2019 relating to the shares held
at the reporting date.
See Note 15-Fair Value Measurement
and Note 22-Other Financial Information, for
additional information.
Subject to market conditions, we
intend to decrease our investment over time
through market transactions, private agreements
or otherwise.
Note 8-Suspended Wells and Other Exploration Expenses
The following table reflects the net changes in suspended
exploratory well costs during 2019, 2018 and 2017:
Millions of Dollars
Beginning balance at January 1
$
1,063
Additions pending the determination of proved reserves
Reclassifications to proved properties
(11)
(37)
(66)
Sales of suspended wells
(54)
(93)
-
Charged to dry hole expense
(10)
(7)
(262)
Ending balance at December 31
$
1,020
*
*Includes $
million of assets held for sale in Australia.
The following table provides an aging of suspended
well balances at December 31:
Millions of Dollars
Exploratory well costs capitalized for a period
of one year or less
$
Exploratory well costs capitalized for a period
greater than one year
Ending balance
$
1,020
*
Number of projects with exploratory well costs
capitalized for a
period greater than one year
*Includes $313 million of assets held for sale in Australia.
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, 2019:
Millions of Dollars
Suspended Since
Total
2016-2018
2013-2015
2004-2012
Greater Poseidon-Australia
(2)(3)
-
NPRA-Alaska
(1)
-
Barossa/Caldita-Australia
(2)(3)
-
Surmont-Canada
(1)
Middle Magdalena Basin-Colombia
(1)
-
-
Narwhal Trend-Alaska
(1)
-
-
Kamunsu East-Malaysia
(2)
-
-
NC 98-Libya
(2)
-
WL4-00-Malaysia
(2)
-
-
Other of $10 million or less each
(1)(2)
Total
$
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
(3)Assets held for sale as of December 31, 2019.
Other Exploration Expenses
In February 2017, we reached a settlement
agreement on our contract for the Athena drilling
rig, initially
secured for our four-well commitment program
in Angola.
As a result of the cancellation, we recognized
a
before-tax charge of $
million net in the first quarter of 2017.
These charges are included in the
“Exploration expenses” line on our consolidated income
statement and in our Other International segment
in
2017.
In 2019, we recorded before-tax dry hole expenses
of $
million due to our decision to discontinue
exploration activities in the Central Louisiana Austin
Chalk trend.
These charges are included in our Lower 48
segment and in the “Exploration expenses” line
on our consolidated income statement.
See Note 9-
Impairments for additional information on our
decision to discontinue these exploration activities.
Note 9-Impairments
During 2019, 2018 and 2017, we recognized the
following before-tax impairment charges:
Millions of Dollars
Alaska
$
-
Lower 48
3,969
Canada
Europe and North Africa
(79)
Asia Pacific and Middle East
-
2,384
$
6,601
In the Lower 48, we recorded impairments
of $
million, primarily related to developed properties
in our
Niobrara asset which were written down to fair value
less costs to sell.
See Note 5-Asset Acquisitions and
Dispositions,
for additional information on this disposition.
The charges discussed below, within this section, are included in the “Exploration
expenses” line on our
consolidated income statement and are not reflected
in the table above.
In our Lower 48 segment, we recorded a before-tax impairment
of $
million for the associated carrying
value of capitalized undeveloped leasehold costs
due to our decision to discontinue exploration
activities
related to our Central Louisiana Austin Chalk
acreage.
In Alaska, we recorded impairments of $
million primarily due to cancelled projects.
In the Lower 48, we recorded impairments
of $
million, primarily related to developed properties
in our
Barnett asset which were written down to fair value
less costs to sell, partly offset by a revision to reflect
finalized proceeds on a separate transaction.
In our Europe and North Africa segment, we recorded
a credit to impairment of $
million, primarily due to
decreased ARO estimates on fields in the
U.K. which have ceased production and
were impaired in prior years,
partly offset by an increased ARO estimate on a field
in Norway which has ceased production.
In Alaska, we recorded impairments of $
million primarily for the associated PP&E
carrying value of our
small interest in the Point Thomson unit.
In the Lower 48, we recorded impairments
of $
3,969
million primarily due to certain developed
properties
which were written down to fair value less costs
to sell.
See Note 5-Asset Acquisitions and Dispositions, for
additional information on our dispositions.
In Canada, we recorded impairments of $
million primarily due to cancelled projects.
In Europe and North Africa, we recorded impairments
of $
million primarily due to reduced volume
forecasts for a field in the U.K. and restructured ownership
and a change in commercial premises for a gas
processing plant in Norway, partly offset by decreased ARO estimates on fields at or
nearing the end of life
which were impaired in prior years.
In Asia Pacific and Middle East, we recorded impairments
of $
2,384
million, including the impairment of our
APLNG investment.
For more information, see the “APLNG”
section of Note 6-Investments, Loans and
Long-Term Receivables.
The charges discussed below, within this section, are included in the “Exploration
expenses” line on our
consolidated income statement and are not reflected
in the table above.
In our Lower 48 segment, we recorded a before-tax impairment
of $
million for the associated carrying
value of capitalized undeveloped leasehold costs
of Shenandoah in deepwater Gulf of Mexico
following the
suspension of appraisal activity by the operator.
Additionally, we recorded a $
million before-tax
impairment for mineral assets primarily
due to plan of development changes.
Note 10-Asset Retirement Obligations and Accrued
Environmental Costs
Asset retirement obligations and accrued environmental
costs at December 31 were:
Millions of Dollars
Asset retirement obligations
$
6,206
7,908
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
6,377
8,086
Asset retirement obligations and accrued environmental
costs due within one year*
(1,025)
(398)
Long-term asset retirement obligations and accrued
environmental costs
$
5,352
7,688
*Classified as a current liability on the balance sheet under “Other accruals.” $
million relates to assets which are held for sale as of
December 31, 2019. For additional information see Note 5-Asset Acquisitions
and Dispositions.
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.
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 2019 and 2018, our overall ARO changed
as follows:
Millions of Dollars
Balance at January 1
$
7,908
7,798
Accretion of discount
New obligations
Changes in estimates of existing obligations
(266)
Spending on existing obligations
(229)
(228)
Property dispositions
(1,920)
(161)
Foreign currency translation
(80)
(240)
Balance at December 31
$
6,206
7,908
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2019 and 2018, were $
million and $
million,
respectively.
We had accrued environmental costs of $
million and $
million at December 31, 2019 and 2018,
respectively, related to remediation activities in the U.S. and Canada.
We had also accrued in Corporate and
Other $
million and $
million of environmental costs associated
with sites no longer in operation at
December 31, 2019 and 2018, respectively.
In addition, $
million and $
million were included at both
December 31, 2019 and 2018, respectively, 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
years.
Expected expenditures for environmental obligations
acquired in various business combinations
are discounted
using a weighted-average
percent discount factor, resulting in an accrued balance for acquired
environmental
liabilities of $
million at December 31, 2019.
The expected future undiscounted payments
related to the
portion of the accrued environmental costs that
have been discounted are: $
million in 2020, $
million in
2021, $
million in 2022, $
million in 2023, $
million in 2024, and $
million for all future years
after 2024.
Note 11-Debt
Long-term debt at December 31 was:
Millions of Dollars
9.125% Debentures due 2021
$
8.20% Debentures due 2025
8.125% Notes due 2030
7.9% Debentures due 2047
7.8% Debentures due 2027
7.65% Debentures due 2023
7.40% Notes due 2031
7.375% Debentures due 2029
7.25% Notes due 2031
7.20% Notes due 2031
7% Debentures due 2029
6.95% Notes due 2029
1,549
1,549
6.875% Debentures due 2026
6.50% Notes due 2039
2,750
2,750
5.951% Notes due 2037
5.95% Notes due 2036
5.95% Notes due 2046
5.90% Notes due 2032
5.90% Notes due 2038
4.95% Notes due 2026
1,250
1,250
4.30% Notes due 2044
4.15% Notes due 2034
3.35% Notes due 2024
3.35% Notes due 2025
2.4% Notes due 2022
Floating rate notes due 2022 at
2.81
% -
3.58
% during 2019 and
2.32
% -
3.52
% during 2018
Industrial Development Bonds due 2035 at
1.08
% -
2.45
% during 2019 and
0.95
% -
1.86
% during 2018
Marine Terminal Revenue Refunding Bonds due 2031 at
1.08
% -
2.45
% during
2019 and
0.88
% -
1.95
% during 2018
Other
Debt at face value
13,971
13,971
Finance leases
Net unamortized premiums, discounts and
debt issuance costs
Total debt
14,895
14,968
Short-term debt
(105)
(112)
Long-term debt
$
14,790
14,856
Maturities of long-term borrowings, inclusive
of net unamortized premiums and discounts,
in 2020 through
2024 are: $
million, $
million, $
million, $
million and $
million, respectively.
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 $
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 $
million or
more by ConocoPhillips, or any of its consolidated
subsidiaries.
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.
We have a $
6.0
billion commercial paper program, which
is primarily a funding source for short-term
working
capital needs.
Commercial paper maturities are generally
limited to
90 days
.
We had no commercial paper
outstanding in programs in place at December
31, 2019 or December 31, 2018.
We had
no
direct outstanding
borrowings or letters of credit under the revolving
credit facility at December 31, 2019 or December
31, 2018.
Since we had
no
commercial paper outstanding and had issued
no letters of credit, we had access to
$
6.0
billion in borrowing capacity under our revolving
credit facility at December 31, 2019.
At both December 31, 2019 and 2018, we had
$
million of certain variable rate demand
bonds (VRDBs)
outstanding which mature
in 2035.
The VRDBs are redeemable at the option of the
bondholders on any
business day.
If they are ever redeemed, we intend to refinance
on a long-term basis, therefore, the VRDBs are
included in the “Long-term debt” line on our consolidated
balance sheet.
For additional information on Finance Leases,
see Note 17
-
Non-Mineral Leases.
Note 12-Guarantees
At December 31, 2019, 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, 2019, 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
2019 exchange rates:
●
During the third
quarter of 2016, we issued a guarantee to facilitate
the withdrawal of our pro-rata
portion of the funds in a project finance reserve
account.
We estimate the remaining term of this
guarantee is
11 years
.
Our maximum exposure under this guarantee is
approximately $
million
and may become payable if an enforcement action
is commenced by the project finance lenders
against APLNG.
At December 31, 2019, the carrying value
of this guarantee is approximately $
million.
●
In conjunction with our original purchase of an ownership
interest in APLNG from Origin Energy in
October 2008, we agreed to reimburse Origin
Energy for our share of the existing contingent liability
arising under guarantees of an existing obligation
of APLNG to deliver natural gas under several
sales
agreements with remaining terms of up to
22 years
.
Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated
to be $
million ($
1.4
billion in the event of intentional or reckless breach)
and would become payable if APLNG fails
to
meet its obligations under these agreements and
the obligations cannot otherwise be mitigated.
Future
payments are considered unlikely, as the payments, or cost of volume delivery, would only be
triggered
if APLNG does not have enough natural gas to
meet these sales commitments and if the co-
venturers do not make necessary equity contributions
into APLNG.
●
We have guaranteed the performance of APLNG with regard to certain other contracts
executed in
connection with the project’s continued development.
The guarantees have remaining terms
of up to
26 years or the life of the venture
.
As of December 31, 2019, we were released from
certain of these
guarantees considered subordinated financial
support to APLNG.
Our remaining maximum potential
amount of future payments related to the remaining
guarantees is approximately $
million and
would become payable if APLNG does not perform.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling
approximately
$
million, which consist primarily of
guarantees of the residual value of leased office buildings,
guarantees
of the residual value of leased corporate aircraft,
and a guarantee for our portion of a joint
venture’s project
finance reserve accounts.
These guarantees have remaining terms of up to
three years
and would become
payable if, upon sale, certain asset values are lower
than guaranteed amounts, business conditions
decline at
guaranteed entities, or as a result of nonperformance
of contractual terms by guaranteed parties.
In conjunction with the disposition of our two
U.K. subsidiaries to Chrysaor E&P Limited,
we will temporarily
continue to support various guarantees and letters
of credit which were provided for the benefit of entities
that
are now affiliates of Chrysaor E&P Limited.
Our maximum potential payment exposure under
these
obligations is approximately $
million.
Chrysaor E&P Limited has agreed to fully
indemnify
ConocoPhillips for any losses suffered by us related to
these obligations.
Indemnifications
Over the years, we have entered into agreements to
sell ownership interests in certain corporations,
joint
ventures and assets that gave rise to qualifying
indemnifications.
These agreements include indemnifications
for taxes, environmental liabilities, employee claims
and litigation.
The terms of these indemnifications vary
greatly.
The majority of these indemnifications are related
to environmental issues, the term is generally
indefinite and the maximum amount of future payments
is generally unlimited.
The carrying amount recorded
for these indemnifications at December 31, 2019,
was approximately $
million.
We amortize the
indemnification liability over the relevant time
period, if one exists, based on the facts and circumstances
surrounding each type of indemnity.
In cases where the indemnification term is
indefinite, we will reverse the
liability when we have information the liability
is essentially relieved or amortize the liability
over an
appropriate time period as the fair value of our indemnification
exposure declines.
Although it is reasonably
possible future payments may exceed amounts recorded,
due to the nature of the indemnifications, it
is not
possible to make a reasonable estimate of the
maximum potential amount of future payments.
Included in the
recorded carrying amount at December 31, 2019,
were approximately $
million of environmental accruals
for known contamination that are included in
the “Asset retirement obligations and accrued
environmental
costs” line on our consolidated balance sheet.
For additional information about environmental
liabilities, see
Note 13-Contingencies and Commitments.
Note 13-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
minimum of the range is accrued.
We do not reduce these liabilities for potential insurance or third-party
recoveries.
If applicable, we accrue receivables for probable
insurance or other third-party recoveries.
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 19-Income Taxes, 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.
When we prepare
our consolidated financial statements, we record
accruals for environmental liabilities based on management’s
best estimates, using all information that is
available at the time.
We measure estimates and base liabilities on
currently available facts, existing technology, and presently enacted laws
and regulations, taking into account
stakeholder and business considerations.
When measuring environmental liabilities,
we also consider our prior
experience in remediation of contaminated sites,
other companies’ cleanup experience, and data released
by
the U.S. EPA or other organizations.
We consider unasserted claims in our determination of environmental
liabilities, and we accrue them in the period they
are both probable and reasonably estimable.
Although liability of those potentially responsible
for environmental remediation costs is generally
joint and
several for federal sites and frequently so for other
sites, we are usually only one of many companies
cited at a
particular site.
Due to the joint and several liabilities, we could
be responsible for all cleanup costs related
to
any site at which we have been designated as a
potentially responsible party.
We have been successful to date
in sharing cleanup costs with other financially
sound companies.
Many of the sites at which we are potentially
responsible are still under investigation by the
EPA or the agency concerned.
Prior to actual cleanup, those
potentially responsible normally assess the
site conditions, apportion responsibility and determine
the
appropriate remediation.
In some instances, we may have no liability
or may attain a settlement of liability.
Where it appears that other potentially responsible
parties may be financially unable to bear their
proportional
share, we consider this inability in estimating
our potential liability, and we adjust our accruals accordingly.
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.
See Note 10-Asset Retirement Obligations and
Accrued Environmental Costs, for a summary of our
accrued environmental liabilities.
Legal Proceedings
We are subject to various lawsuits and claims including but not limited to matters
involving oil and gas royalty
and severance tax payments, gas measurement and
valuation methods, contract disputes,
environmental
damages, climate change, personal injury, and property damage.
Our primary exposures for such matters
relate to alleged royalty and tax underpayments
on certain federal, state and privately owned
properties and
claims of alleged environmental contamination
from historic operations.
We will continue to defend ourselves
vigorously in these matters.
Our legal organization applies its knowledge, experience
and professional judgment to the specific
characteristics of our cases, employing a litigation
management process to manage and monitor the
legal
proceedings against us.
Our process facilitates the early evaluation and
quantification of potential exposures in
individual cases.
This process also enables us to track those cases that
have been scheduled for trial and/or
mediation.
Based on professional judgment and experience
in using these litigation management tools and
available information about current developments
in all our cases, our legal organization regularly assesses
the
adequacy of current accruals and determines if
adjustment of existing accruals, or establishment
of new
accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and
processing companies
not associated with financing arrangements.
Under these agreements, we may be required
to provide any such
company with additional funds through advances
and penalties for fees related to throughput capacity
not
utilized.
In addition, at December 31, 2019, we had performance
obligations secured by letters of credit
of
$
million (issued as direct bank letters of
credit) related to various purchase commitments
for materials,
supplies, commercial activities and services incident
to the ordinary conduct of business.
In 2007, ConocoPhillips was unable to reach agreement
with respect to the empresa mixta structure
mandated
by the Venezuelan government’s Nationalization Decree.
As a result, Venezuela’s
national oil company,
Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’
interests in the Petrozuata and Hamaca heavy oil
ventures and the offshore Corocoro development project.
In
response to this expropriation, ConocoPhillips
initiated international arbitration on November 2,
2007, with the
ICSID.
On September 3, 2013, an ICSID arbitration tribunal
held that Venezuela unlawfully expropriated
ConocoPhillips’ significant oil investments
in June 2007.
On January 17, 2017, the Tribunal reconfirmed the
decision that the expropriation was unlawful.
In March 2019, the Tribunal unanimously ordered the
government of Venezuela to pay ConocoPhillips approximately $
8.7
billion in compensation for the
government’s unlawful expropriation of the company’s investments in Venezuela in 2007.
ConocoPhillips has
filed a request for recognition of the award in several
jurisdictions.
On August 29, 2019, the ICSID Tribunal
issued a decision rectifying the award and reducing
it by approximately $
million.
The award now stands
at $
8.5
billion plus interest.
The government of Venezuela sought annulment of the award.
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 $
billion
under their
agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In
August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC
award, plus interest through the payment period, including initial payments totaling approximately $500
million within a period of 90 days from the time of signing of the settlement agreement. The balance of the
settlement is to be paid quarterly over a period of four and a half years.
To date, ConocoPhillips has received
approximately $
million.
Per the settlement, PDVSA recognized the ICC
award as a judgment in various
jurisdictions, and ConocoPhillips agreed to suspend
its legal enforcement actions.
ConocoPhillips sent notices
of default to PDVSA on October 14 and November
12, 2019, and to date PDVSA failed to
cure its breach.
As
a result, ConocoPhillips has resumed legal enforcement
actions.
ConocoPhillips has ensured that the
settlement and any actions thereof meet all appropriate
U.S. regulatory requirements, including those related
to
any applicable sanctions imposed by the U.S. against
Venezuela.
In 2016, ConocoPhillips filed a separate and independent
arbitration under the rules of the ICC against
PDVSA under the contracts that had established the
Corocoro project.
On August 2, 2019, the ICC Tribunal
awarded ConocoPhillips approximately $
million 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
Ve
nezuela.
In February 2017, the ICSID Tribunal unanimously awarded Burlington
Resources, Inc., a wholly owned
subsidiary of ConocoPhillips, $
million for Ecuador’s unlawful expropriation of
Burlington’s investment in
Blocks 7 and 21, in breach of the U.S.-Ecuador
Bilateral Investment Treaty.
The tribunal also issued a
separate decision finding Ecuador to be entitled
to $
million for environmental and infrastructure
counterclaims.
In December 2017, Burlington and Ecuador
entered into a settlement agreement by which
Ecuador paid Burlington $
million in two installments.
The first installment of $
million was paid in
December 2017, and the second installment
of $
million was paid in April 2018.
The settlement included
an offset for the counterclaims decision, of which Burlington
is entitled to a contribution from Perenco
Ecuador Limited, its co-venturer and consortium
operator, pursuant to a joint and several liability provision in
the JOA.
In September 2019, a separate ICSID Tribunal issued an award
in the Perenco arbitration, ordering
Perenco to pay an additional $
million to Ecuador for its environmental counterclaim.
Burlington and
Perenco will reconcile their shares of the environmental
and infrastructure counterclaims according
to their
JOA participating interests, and we expect Burlington’s share will be immaterial.
In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips
Senegal B.V.
in connection
with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016.
In
February 2020, the ICC Tribunal issued an award dismissing
FAR Ltd.’s
claims in the arbitration.
In late 2017, ConocoPhillips (U.K.) Limited
(CPUKL) initiated United Nations Commission
on International
Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral
Investment Treaty relating to a tax dispute arising from the
2012 sale of ConocoPhillips (U.K.) Cuu Long
Limited and ConocoPhillips (U.K.) Gama Limited.
The parties entered into a settlement agreement
in October
2019, and the arbitration was dismissed in
December 2019 as a result of this agreement.
In 2017 and 2018, cities, counties, and a state
government in California, New York, Washington, Rhode Island
and Maryland, as well as the Pacific Coast Federation
of Fishermen’s Association, Inc., have filed lawsuits
against oil and gas companies, including ConocoPhillips,
seeking compensatory damages and equitable
relief
to abate alleged climate change impacts.
ConocoPhillips is vigorously defending against
these lawsuits.
The
lawsuits brought by the Cities of San Francisco,
Oakland and New York have been dismissed by the district
courts and appeals are pending.
Lawsuits filed by other cities and counties
in California and Washington are
currently stayed pending resolution of the appeals
brought by the Cities of San Francisco and
Oakland to the
U.S. Court of Appeals for the Ninth Circuit.
Lawsuits filed in Maryland and Rhode Island
are proceeding in
state court while rulings in those matters, on the
issue of whether the matters should proceed
in state or federal
court, are on appeal to the U.S. Court of Appeals
for the Fourth Circuit and First Circuit,
respectively.
Several Louisiana parishes and individual landowners
have filed lawsuits against oil and gas companies,
including ConocoPhillips, seeking compensatory
damages in connection with historical oil
and gas operations
in Louisiana.
All parish lawsuits are stayed pending an appeal
to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or
state court.
ConocoPhillips will vigorously defend against
these lawsuits.
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
the company’s business.
The aggregate amounts of estimated payments
under these various agreements are:
2020-$
million; 2021-$
million; 2022-$
million; 2023-$
million; 2024-$
million; and 2025 and
after-$
million.
Total payments under the agreements were $
million in 2019, $
million in 2018 and
$
million in 2017.
Note 14-Derivative and Financial Instruments
We use futures, forwards, swaps and options in various markets to meet our customer
needs and capture
market opportunities.
Our commodity business primarily consists of
natural gas, crude oil, bitumen, LNG and
NGLs.
Our derivative instruments are held at fair value
on our consolidated balance sheet.
Where these balances have
the right of setoff, they are presented on a net basis.
Related cash flows are recorded as operating
activities on
our consolidated statement of cash flows.
On our consolidated income statement, realized
and unrealized gains
and losses are recognized either on a gross basis
if directly related to our physical business
or a net basis if held
for trading.
Gains and losses related to contracts that meet
and are designated with the NPNS exception are
recognized upon settlement.
We generally apply this exception to eligible crude contracts.
We do not use
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
Assets
Prepaid expenses and other current assets
$
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
The gains (losses) from commodity derivatives
incurred, and the line items where they appear
on our
consolidated income statement were:
Millions of Dollars
Sales and other operating revenues
$
Other income
-
Purchased commodities
(118)
(41)
(61)
The table below summarizes our material net exposures
resulting from outstanding commodity
derivative
contracts:
Open Position
Long/(Short)
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
(5)
(17)
Basis
(23)
(1)
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.
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
Assets
Prepaid expenses and other current assets
$
Liabilities
Other accruals
Other liabilities and deferred credits
-
The losses from foreign currency exchange derivatives
incurred and the line item where they appear
on our
consolidated income statement were:
Millions of Dollars
Foreign currency transaction losses
$
We had the following net notional position of outstanding foreign currency exchange
derivatives:
In Millions
Notional Currency
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy British pound
USD
-
Sell British pound, buy other currencies*
GBP
-
Buy British pound, sell euro
GBP
-
Sell Canadian dollar, buy U.S. dollar
CAD
1,337
1,242
*Primarily euro and Norwegian krone.
In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion
CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar.
The collar expired during the second quarter of 2019 and we entered into new foreign currency exchange
forward contracts to sell $1.35 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.
●
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.
●
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:
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
Cash
$
Demand Deposits
1,483
-
-
-
Time Deposits
Remaining maturities from 1 to 90 days
2,030
3,509
1,395
-
Remaining maturities from 91 to 180 days
-
-
-
Commercial Paper
Remaining maturities from 1 to 90 days
1,069
U.S. Government Obligations
Remaining maturities from 1 to 90 days
1,301
-
-
$
5,079
5,915
2,929
The following table reflects our investments
in debt securities classified as available
for sale at December 31,
2019 which are carried at fair value:
Millions of Dollars
Carrying Amount
Cash and
Cash
Equivalents
Short-Term
Investments
Investments
and Long-
Term
Receivables
Corporate Bonds
Remaining maturities within one year
$
-
Remaining maturities greater than one year through
five years
-
-
Commercial Paper
Remaining maturities within one year
-
U.S. Government Obligations
Remaining maturities within one year
-
-
Remaining maturities greater than one year through
five years
-
-
Asset-backed Securities
Remaining maturities greater than one year through
five 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,
2019:
Millions of Dollars
Amortized Cost
Basis
Fair Value
Major Security Type
Corporate bonds
$
Commercial paper
U.S. government obligations
Asset-backed securities
$
Gross unrealized gains and gross unrealized losses
included in other comprehensive income related
to
investments in debt securities classified as available
for sale as of December 31, 2019, were negligible.
There were no other-than-temporary impairments
recognized in earnings or in other comprehensive
income
during the year ended December 31, 2019.
Gross realized gains and gross realized losses
included in earnings from sales and redemptions
of investments
in debt securities classified as available for sale
during the year ended December 31, 2019,
were negligible.
The cost of securities sold and redeemed is determined
using the specific identification method.
Credit Risk
Financial instruments potentially exposed to concentrations
of credit risk consist primarily of cash equivalents,
short-term investments, long-term investments
in debt securities, OTC derivative contracts and trade
receivables.
Our cash equivalents and short-term investments
are placed in high-quality commercial paper,
government money market funds, government debt
securities,
time deposits with major international banks and
financial institutions,
and high-quality corporate bonds.
Our long-term investments in debt securities
are
placed in high-quality corporate bonds, U.S. government
obligations, and asset-backed securities.
The credit risk from our OTC derivative contracts,
such as forwards, swaps and options, derives
from the
counterparty to the transaction.
Individual counterparty exposure is managed
within predetermined credit
limits and includes the use of cash-call margins when appropriate,
thereby reducing the risk of significant
nonperformance.
We also use futures, swaps and option contracts that have a negligible credit risk
because
these trades are cleared 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 do not generally require collateral to limit the exposure to loss;
however, we will sometimes use letters of credit, prepayments
and 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, 2019 and
December 31, 2018, was $
million and $
million,
respectively.
For these instruments,
no collateral
was posted as of December 31, 2019 or December 31,
2018.
If our credit rating had been downgraded below
investment grade on December 31, 2019,
we would be
required to post $
million of additional collateral, either with
cash or letters of credit.
Note 15-Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at a reporting
date using an exit
price (i.e., the price that would be received to sell
an asset or paid to transfer a liability) and disclosed
according to the quality of valuation inputs under
the following hierarchy:
●
Level 1: Quoted prices (unadjusted) in an active
market for identical assets or liabilities.
●
Level 2: Inputs other than quoted prices that
are directly or indirectly observable.
●
Level 3: Unobservable inputs that are significant
to the fair value of assets or liabilities.
The classification of an asset or liability
is based on the lowest level of input significant
to its fair value.
Those
that are initially classified as Level 3 are subsequently
reported as Level 2 when the fair value derived
from
unobservable inputs is inconsequential to the overall
fair value, or if corroborated market data becomes
available.
Assets and liabilities initially reported as Level
2 are subsequently reported as Level 3 if
corroborated market data is no longer available.
Transfers occur at the end of the reporting period.
There were
no material transfers in or out of Level 1 during
2019 or 2018.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair
value on a recurring basis primarily include
our investment in
Cenovus Energy shares,
our investments
in debt securities classified as available for sale,
and commodity
derivatives.
●
Level 1 derivative assets and liabilities primarily
represent exchange-traded futures and options that are
valued using unadjusted prices available from the
underlying exchange.
Level 1 also includes our
investment in common shares of Cenovus Energy, which is valued using quotes for shares
on the NYSE,
and our investments in U.S. government obligations
classified as available for sale debt securities,
which
are valued using exchange prices.
●
Level 2 derivative assets and liabilities primarily
represent OTC swaps, options and forward purchase
and
sale contracts that are valued using adjusted exchange
prices, prices provided by brokers or pricing
service
companies that are all corroborated by market
data.
Level 2 also includes our investments
in debt
securities classified as available for sale including
investments in corporate bonds, commercial
paper, and
asset-backed securities 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, 2019
December 31, 2018
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investment in Cenovus Energy
$
2,111
-
-
2,111
1,462
-
-
1,462
Investments in debt securities
-
Commodity derivatives
Total assets
$
2,308
2,674
1,698
1,912
Liabilities
Commodity derivatives
$
Total liabilities
$
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, 2019
Assets
$
Liabilities
December 31, 2018
Assets
$
-
Liabilities
At December 31, 2019 and December 31, 2018,
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, 2019
Net PP&E (held for sale)
November 30, 2019
$
-
-
December 31, 2019
-
-
Equity Method Investments
March 31, 2019
-
-
May 31, 2019
-
-
Year
ended December 31, 2018
Net PP&E (held for sale)
March 31, 2018
$
-
-
September 30, 2018
-
-
Net PP&E (held for sale)
Net PP&E held for sale was written down to fair
value, less costs to sell.
The fair value of each asset was
determined by its negotiated selling price (Level
1) or information gathered during marketing
efforts (Level 3).
For additional information see Note 5-Asset
Acquisitions and Dispositions.
Equity Method Investments
During 2019, certain equity method investments
were determined to have fair values below their
carrying
amounts, and the impairments were considered to
be other than temporary under the guidance of
FASB ASC
Topic 323.
During 2019, investments using Level 1 inputs
were written down to fair value, less costs to
sell,
determined by negotiated selling prices.
For additional information, see Note 5-Asset
Acquisitions and
Dispositions.
During 2019, an investment using Level 2 inputs
was determined to have a fair value below its
carrying value, and was written down to fair value.
For additional information, see Note 3-Variable Interest
Entities.
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 shares: See Note 7-Investment
in Cenovus Energy for a discussion of
the carrying value and fair value of our investment
in Cenovus Energy shares.
●
Investments in debt securities classified as available
for sale: The fair value of investments in debt
securities categorized as Level 1 in the fair
value hierarchy is measured using exchange
prices.
The
fair value of investments in debt securities
categorized as Level 2 in the fair value hierarchy is
measured using pricing provided by brokers or
pricing service companies that are corroborated
with
market data.
See Note 14-Derivatives and Financial Instruments,
for additional information.
●
Loans and advances-related parties: The carrying
amount of floating-rate loans approximates
fair
value.
The fair value of fixed-rate loan activity is
measured using market observable data and is
categorized as Level 2 in the fair value hierarchy.
See Note 6-Investments, Loans and Long-Term
Receivables, for additional information.
●
Accounts payable (including related parties)
and floating-rate debt: The carrying amount of accounts
payable and floating-rate debt reported on the balance
sheet approximates fair value.
●
Fixed-rate debt: The estimated fair value of fixed-rate
debt is measured using prices available
from a
pricing service that is corroborated by market
data; therefore, these liabilities are categorized
as Level
2 in the fair value hierarchy.
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
Financial assets
Investment in Cenovus Energy
$
2,111
1,462
2,111
1,462
Commodity derivatives
Investments in debt securities
-
-
Total loans and advances-related parties
Financial liabilities
Total debt, excluding finance leases
14,175
14,191
18,108
16,147
Commodity derivatives
Commodity Derivatives
At December 31, 2019, commodity derivative
assets and liabilities are presented net with $
million in
obligations to return cash collateral and $
million of rights to reclaim cash collateral,
respectively.
At
December 31, 2018, commodity derivative assets
and liabilities are presented net with
no
obligations to return
cash collateral and $
million of rights to reclaim cash collateral,
respectively.
Note 16-Equity
Common Stock
The changes in our shares of common stock, as categorized
in the equity section of the balance sheet,
were:
Shares
Issued
Beginning of year
1,791,637,434
1,785,419,175
1,782,079,107
Distributed under benefit plans
4,014,769
6,218,259
3,340,068
End of year
1,795,652,203
1,791,637,434
1,785,419,175
Held in Treasury
Beginning of year
653,288,213
608,312,034
544,809,771
Repurchase of common stock
57,495,601
44,976,179
63,502,263
End of year
710,783,814
653,288,213
608,312,034
Preferred Stock
We have authorized
million shares of preferred stock, par value
$
0.01
per share,
none
of which was issued
or outstanding at December 31, 2019 or 2018.
Noncontrolling Interests
At December 31, 2019 and 2018, we had $
million and $
million outstanding, respectively, of equity in
less-than-wholly owned consolidated subsidiaries
held by noncontrolling interest owners.
For both periods,
the amounts were related to the Darwin LNG
and Bayu-Darwin Pipeline operating joint
ventures we control.
Repurchase of Common Stock
As of December 31, 2019, we had announced a total
authorization to repurchase $
billion of our common
stock.
Repurchase of shares began in November 2016,
and totaled
168,553,141
shares at a cost of $
9,625
million, through December 31, 2019.
In February 2020, we announced that the
Board of Directors approved
an increase to our repurchase authorization
from $15 billion to $
billion, to support our plan for future share
repurchases.
Note 17-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 12-Guarantees.
There are no significant restrictions
imposed on us by the lease agreements with regard
to dividends, asset dispositions or borrowing
ability.
Certain arrangements may contain both lease and
non-lease components and we determine
if an arrangement is
or contains a lease at contract inception.
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 recognize 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.
As of December 31, 2018, $
million of finance lease assets (net of accumulated
DD&A) and $
million of finance lease liabilities were
recorded on our consolidated balance sheet
associated with these leases.
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.
In connection with our adoption of ASC Topic 842, we have recorded on our
consolidated balance sheet $
million of operating leases executed by investee
companies accounted for under the proportionate
consolidation method of accounting on a proportional
basis consistent with our ownership interest
in the
investee company.
The following tables summarize the finance leases
amounts that were reflected on our consolidated
balance
sheet as of December 31, 2018, the operating
leases impact of adopting ASC Topic 842, and the right-of-use
asset and lease liability balances reflected for both
operating and finance leases on our consolidated
balance
sheet as of December 31, 2019:
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
Amounts recognized in line items in our Consolidated
Balance Sheet upon adoption of ASC Topic 842
Right-of-Use Assets
Properties, plants and equipment
Gross
$
1,044
Accumulated depreciation, depletion and amortization
(550)
Net properties, plants and equipment as of December
31, 2018
$
Adoption of ASC Topic 842 as of January 1, 2019
$
Lease Liabilities
Short-term debt
$
Long-term debt
Total finance leases debt as of December 31, 2018
$
Adoption of ASC Topic 842 as of January 1, 2019
$
Amounts recognized in line items in our Consolidated
Balance Sheet at December 31, 2019
Right-of-Use Assets
Properties, plants and equipment
Gross
$
1,039
Accumulated depreciation, depletion and amortization
(649)
Net properties, plants and equipment
*
$
Prepaid expenses and other current assets
$
Other assets
* Includes proportionately consolidated finance lease assets (net of
accumulated depreciation, depletion and amortization) of $
million.
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
Lease Liabilities
Short-term debt
*
$
Other accruals
$
Long-term debt
*
Other liabilities and deferred credits
Total lease liabilities
$
$
*
Short-term debt and long-term debt include proportionately consolidated finance
lease liabilities of $
million and $
million, respectively.
The following table summarizes our lease costs
for 2019:
Millions of Dollars
Lease Cost
*
Operating lease cost
$
Finance lease cost
Amortization of right-of-use assets
Interest on lease liabilities
Short-term lease cost
**
Total lease cost
***
$
*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.
Our future short-term lease commitments amount to $
million, of
which $
million is related to leases whose terms have not yet commenced
as of December 31, 2019.
***Variable lease cost and sublease income are immaterial for the period presented and therefore are not included in the table above.
The following table summarizes the lease terms
and discount rates:
December 31, 2019
Lease Term and Discount Rate
Weighted-average term (years)
Operating leases
5.19
Finance leases
8.70
Weighted-average discount rate (percent)
Operating leases
3.10
Finance leases
5.53
The following table summarizes other lease information
for 2019:
Millions of Dollars
Other Information
*
Cash paid for amounts included in the measurement
of lease liabilities
Operating cash flows from operating leases
$
Operating cash flows from finance leases
Financing cash flows from finance leases
Right-of-use assets obtained in exchange for
operating lease liabilities
$
Right-of-use assets obtained in exchange for
finance lease liabilities
*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, 2019:
Millions of Dollars
Operating
Leases
Finance
Leases
Maturity of Lease Liabilities
$
Remaining years
Total
*
1,019
Less: portion representing imputed interest
(87)
(160)
Total lease liabilities
$
*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.
At December 31, 2018, future minimum payments
due under finance (capital) leases pursuant
to
ASC Topic 840 were:
Millions
of Dollars
$
Remaining years
Total
Less: portion representing imputed interest
(195)
Capital lease obligations
$
At December 31, 2018, future undiscounted minimum
rental payments due under noncancelable operating
leases pursuant to ASC Topic 840 were:
Millions
of Dollars
$
Remaining years
Total
1,394
Less: income from subleases
(7)
Net minimum operating lease payments
$
1,387
For the years ended December 31, operating
lease rental expense pursuant to ASC Topic 840 was:
Millions of Dollars
Total rentals
$
Less: sublease rentals
(16)
(20)
$
Note 18-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
U.S.
Int’l.
U.S.
Int’l.
Change in Benefit Obligation
Benefit obligation at January 1
$
2,136
3,438
3,236
3,845
Service cost
Interest cost
Plan participant contributions
-
-
Plan amendments
-
-
-
-
-
Actuarial (gain) loss
(44)
(259)
(10)
Benefits paid
(253)
(147)
(507)
(143)
(59)
(67)
Curtailment
-
(69)
(4)
(3)
-
-
Settlement
-
-
(730)
-
-
-
Recognition of termination benefits
-
-
-
-
Foreign currency exchange rate change
-
-
(199)
(1)
Benefit obligation at December 31*
$
2,319
3,880
2,136
3,438
*Accumulated benefit obligation portion of above at
December 31:
$
2,161
3,594
1,969
3,066
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
$
1,336
3,358
2,541
3,647
-
-
Actual return on plan assets
(112)
(106)
-
-
Company contributions
Plan participant contributions
-
-
Benefits paid
(253)
(147)
(507)
(143)
(59)
(67)
Settlement
-
-
(730)
-
-
-
Foreign currency exchange rate change
-
-
(198)
-
-
Fair value of plan assets at December 31
$
1,591
4,306
1,336
3,358
-
-
Funded Status
$
(728)
(800)
(80)
(216)
(218)
Millions of Dollars
Pension Benefits
Other Benefits
U.S.
Int’l.
U.S.
Int’l.
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Noncurrent assets
$
-
-
-
-
Current liabilities
(21)
(6)
(59)
(4)
(42)
(44)
Noncurrent liabilities
(707)
(333)
(741)
(308)
(174)
(174)
Total recognized
$
(728)
(800)
(80)
(216)
(218)
Weighted-Average Assumptions Used to
Determine Benefit Obligations at
December 31
Discount rate
3.25
%
2.35
4.25
3.05
3.10
4.05
Rate of compensation increase
4.00
3.35
4.00
3.65
-
Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost for
Years
Ended December 31
Discount rate
3.95
%
2.90
3.80
2.90
4.05
3.30
Expected return on plan assets
5.80
4.10
5.80
4.30
-
Rate of compensation increase
4.00
3.65
4.00
3.75
-
For both U.S. and international pensions, 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.
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
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
$
(21)
Unrecognized prior service cost (credit)
-
(2)
-
(4)
(183)
(216)
Millions of Dollars
Pension Benefits
Other Benefits
U.S.
Int’l.
U.S.
Int’l.
Sources of Change in Other
Comprehensive Income (Loss)
Net gain (loss) arising during the period
$
(79)
(177)
(27)
Amortization of actuarial (gain) loss included
in income (loss)*
(2)
(1)
Net change during the period
$
(29)
Prior service credit (cost) arising during the
period
$
-
-
-
(7)
-
-
Amortization of prior service cost (credit)
included in income (loss)
-
(2)
-
(5)
(33)
(35)
Net change during the period
$
-
(2)
-
(12)
(33)
(35)
*Includes settlement losses recognized in 2019 and 2018.
Included in accumulated other comprehensive
loss at December 31, 2019, were the following
before-tax
amounts that are expected to be amortized into
net periodic benefit cost during 2020:
Millions of Dollars
Pension
Other
Benefits
Benefits
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
$
Unrecognized prior service credit
-
(2)
(31)
For our tax-qualified pension plans with projected
benefit obligations in excess of plan
assets, the projected
benefit obligation, the accumulated benefit obligation,
and the fair value of plan assets were $
2,073
million,
$
1,919
million, and $
1,635
million, respectively, at December 31, 2019, and $
1,871
million, $
1,737
million,
and $
1,373
million, respectively, at December 31, 2018.
For our unfunded nonqualified key employee supplemental
pension plans, the projected benefit obligation and
the accumulated benefit obligation were $
million and $
million, respectively, at December 31, 2019,
and were $
million and $
million, respectively, at December 31, 2018.
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
U.S.
Int’l.
U.S.
Int’l.
U.S.
Int’l.
Components of Net
Periodic Benefit Cost
Service cost
$
Interest cost
Expected return on plan
assets
(74)
(138)
(114)
(155)
(132)
(158)
-
-
-
Amortization of prior
service cost (credit)
-
(2)
-
(5)
(6)
(33)
(35)
(36)
Recognized net actuarial
loss (gain)
(2)
(1)
(3)
Settlements
-
-
-
-
-
-
Net periodic benefit cost
$
(26)
(27)
(28)
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.
In 2018, we purchased a group annuity contract
from Prudential and transferred $
million of future benefit
obligations from the U.S. qualified pension plan to
Prudential.
The purchase of the group annuity contract
was
funded directly by plan assets of the U.S. qualified
pension plan.
Effective January 1, 2019, the Cash Balance
Account (Title II) of the ConocoPhillips Retirement Plan,
a U.S. qualified pension plan, was closed to new
entrants.
New employees and rehires on or after January
1, 2019, and employees that elected to opt out of
Title II will no longer receive pay credits to their Cash Balance
Account and instead will be eligible for a
Company Retirement Contribution (CRC) as
described in the Defined Contribution Plans section.
We recognized pension settlement losses of $
million in 2019, $
million in 2018, and $
million in
2017 as lump-sum benefit payments from certain
U.S. pension plans exceeded the sum of service
and interest
costs for those plans and led to recognition of settlement
losses.
The sale of two ConocoPhillips U.K. subsidiaries
completed during the third quarter of 2019 led
to a
significant reduction of future services of active
employees in certain international pension
plans, resulting in a
curtailment.
In conjunction with the recognition of the curtailment,
the fair market values of pension plan
assets were updated, the pension benefit obligation
was remeasured, and the net pension asset
decreased by
$
million, resulting in a corresponding decrease
to other comprehensive income.
This is primarily a result of
a decrease in the discount rate from
2.90
percent at December 31, 2018 to
1.80
percent at September 30, 2019
offset by a decrease in the pension benefit obligation from
curtailment.
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
percent of the unamortized balance each year.
We have multiple nonpension 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
percent in
2020 that declines to
percent by
.
The measurement of the U.S. post-65 retiree
medical accumulated
postretirement benefit obligation assumes an ultimate
health care cost trend rate of
percent achieved in 2020
that increases to
percent by
.
A one-percentage-point change in the assumed
health care cost trend rate
would be immaterial to ConocoPhillips.
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
percent equity
securities,
percent debt securities,
percent real estate and
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, 2019 and 2018.
●
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, 2019, the participating interest
in the annuity contract was valued at
$
million and consisted of $
million in debt securities, less $
million for the accumulated
benefit obligation covered by the contract.
At December 31, 2018, the participating interest
in the
annuity contract was valued at $
million and consisted of $
million in debt securities, less
$
million for the accumulated benefit obligation
covered by the contract.
The net change from 2018 to
2019 is due to an increase in the fair value of the
underlying investments of $
million offset by a
decrease in the present value of the contract obligation
of $
million.
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.
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
Equity securities
U.S.
$
-
-
-
International
-
-
-
-
Mutual funds
-
-
-
Debt securities
Government
-
-
-
-
1,412
-
-
1,412
Corporate
-
-
-
-
-
-
Mutual funds
-
-
-
-
-
-
Cash and cash equivalents
-
-
-
-
-
-
Derivatives
-
-
-
-
-
-
Real estate
-
-
-
-
-
-
Total in fair value hierarchy
$
2,859
3,258
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
-
-
-
-
-
-
Debt securities
Common/collective trusts
-
-
-
-
-
-
Cash and cash equivalents
-
-
-
-
-
-
-
Real estate
-
-
-
-
-
-
Total**
$
1,496
2,859
4,297
*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 $
million and net receivables related to security
transactions of $
million.
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
Equity securities
U.S.
$
-
-
-
International
-
-
-
-
Mutual funds
-
-
-
Debt securities
Government
-
-
-
-
-
-
Corporate
-
-
-
-
-
-
Mutual funds
-
-
-
-
-
-
Cash and cash equivalents
-
-
-
-
-
-
Time deposits
-
-
-
-
-
-
Derivatives
-
-
-
-
(17)
-
-
(17)
Real estate
-
-
-
-
-
-
Total in fair value hierarchy
$
2,137
2,442
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
-
-
-
-
-
-
Debt securities
Common/collective trusts
-
-
-
-
-
-
Cash and cash equivalents
-
-
-
-
-
-
-
Real estate
-
-
-
-
-
-
Total**
$
1,249
2,137
3,345
*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 $
million and net receivables related to security
transactions of $
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 2020, we expect to contribute approximately $
million to our domestic qualified and nonqualified
pension and postretirement benefit plans and $
million to
our international qualified and nonqualified
pension and postretirement benefit plans.
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.
$
2025-2029
Severance Accrual
The following table summarizes our severance accrual
activity for the year ended December 31, 2019:
Millions of Dollars
Balance at December 31, 2018
$
Accruals
(1)
Benefit payments
(24)
Balance at December 31, 2019
$
Of the remaining balance at December 31, 2019,
$
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
percent of their eligible pay, subject to statutory limits, in the CPSP to
a choice of
approximately
investment options.
Employees who participate in the CPSP and contribute
percent of
their eligible pay receive a
percent company cash match with a potential
company discretionary cash
contribution of up to
percent.
Effective January 1, 2019, new employees, rehires, and
employees that elected
to opt out of Title II are eligible to receive a CRC of
percent of eligible pay into their CPSP.
After
three
years
of service with the company, the employee is
percent vested in any CRC.
Company contributions
charged to expense for the CPSP and predecessor plans
were $
million in 2019, $
million in 2018, and
$
million in 2017.
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 $
million in 2019, $
million in 2018, and $
million in 2017.
Share-Based Compensation Plans
The 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips (the Plan) was approved
by
shareholders in May 2014.
Over its
-year life, the Plan allows the issuance of
up to
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 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, and no new awards shall be granted under
the prior
plans.
Of the 79 million shares available for issuance
under the Plan, no more than
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 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 income (loss) and the
associated tax benefit for the years ended
December 31 were as follows:
Millions of Dollars
Compensation cost
$
Tax benefit
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.
The fair market values of the options granted in
2017 were measured on the date of grant
using the
Black-Scholes-Merton option-pricing model.
The weighted-average assumptions used were as follows:
Assumptions used
Risk-free interest rate
2.24
%
Dividend yield
4.00
%
Volatility
factor
28.12
%
Expected life (years)
6.39
There were no ranges in the assumptions used to
determine the fair market values of our options
granted in
2017.
We believe our historical volatility for periods prior to the 2012 separation of our
Downstream businesses is no
longer relevant in estimating expected volatility.
For 2017,
expected volatility was based on the weighted-
average blend of the company’s historical stock price volatility from
May 1, 2012 (the date of separation of our
Downstream businesses) through the stock option
grant date and the average historical
stock price volatility of
a group of peer companies for the expected term
of the options.
The following summarizes our stock option activity
for the year ended December 31, 2019:
Millions of Dollars
Weighted-Average
Aggregate
Options
Exercise Price
Intrinsic Value
Outstanding at December 31, 2018
19,379,677
$
52.88
$
Exercised
(1,339,480)
36.28
Forfeited
-
Expired or cancelled
-
Outstanding at December 31, 2019
18,040,197
$
54.11
$
Vested at December 31, 2019
17,922,026
$
54.14
$
Exercisable at December 31, 2019
17,172,815
$
54.33
$
The weighted-average remaining contractual term
of outstanding options, vested options and exercisable
options at December 31, 2019, was
4.43
years,
4.41
years and
4.29
years, respectively.
The weighted-average
grant date fair value of stock option awards granted
during 2017 was $
9.18
.
The aggregate intrinsic value of
options exercised was $
million in 2018 and $
million in 2017.
During 2019, we received $
million in cash and realized a tax benefit
of $
million from the exercise of
options.
At December 31, 2019, the remaining unrecognized
compensation expense from unvested options
was
zero
.
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 quarterly
cash payment of a 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, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
7,546,973
$
43.41
Granted
2,045,503
67.77
Forfeited
(99,748)
62.93
Issued
(3,269,682)
34.32
$
Outstanding at December 31, 2019
6,223,046
$
55.99
Not Vested at December 31, 2019
4,185,141
56.17
At December 31, 2019,
the remaining unrecognized compensation
cost from the unvested stock-settled units
was $
million, which will be recognized over
a weighted-average period of
1.71
years, the longest period
being
2.73
years.
The weighted-average grant date fair value
of stock unit awards granted during 2018 and
2017 was $
52.45
and $
48.77
, respectively.
The total fair value of stock units issued during
2018 and 2017 was
$
million and $
million, respectively.
Cash-Settled
Beginning in 2018, cash-settled executive restricted stock units 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.
The following summarizes our cash-settled stock
unit activity for the year ended December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
376,608
$
62.21
Granted
319,552
68.20
Forfeited
(6,914)
61.35
Issued
(92,255)
61.61
$
Outstanding at December 31, 2019
596,991
$
64.54
Not Vested at December 31, 2019
153,457
64.54
At December 31, 2019,
the remaining unrecognized compensation
cost from the unvested cash-settled units
was $
million, which will be recognized over a
weighted-average period of
1.70
years, the longest period
being
2.12
years.
The weighted-average grant date fair value
of stock unit awards granted during 2018
was
$
53.68
.
The total fair value of stock units issued during
2018 was $
million.
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 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, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
2,335,542
$
50.45
Granted
77,841
68.90
Forfeited
-
Issued
(388,559)
53.66
$
Outstanding at December 31, 2019
2,024,824
$
50.55
Not Vested at December 31, 2019
15,616
$
47.80
At December 31, 2019,
the remaining unrecognized compensation
cost from unvested stock-settled
performance share awards was
zero
.
The weighted-average grant date fair value of
stock-settled PSUs granted
during 2018 and 2017 was $
53.28
and $
49.76
, respectively.
The total fair value of stock-settled PSUs issued
during 2018 and 2017 was $
million and $
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, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
1,131,007
$
62.21
Granted
1,958,043
68.90
Forfeited
-
Settled
(2,479,776)
69.10
$
Outstanding at December 31, 2019
609,274
$
64.54
Not Vested at December 31, 2019
38,487
$
64.54
At December 31, 2019,
the remaining unrecognized compensation
cost from unvested cash-settled
performance share awards was
zero
.
The weighted-average grant date fair value of
cash-settled PSUs granted
during 2018 and 2017 was $
53.28
and $
49.76
, respectively.
The total fair value of cash-settled performance
share awards settled during 2018 and 2017
was $
million and $
million, respectively.
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 or as part of an executive
compensation program that
has been discontinued.
Generally, the recipients of the restricted shares or units receive a quarterly dividend
or
dividend equivalent.
The following summarizes the aggregate activity
of these restricted shares and units for the
year ended
December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
1,107,315
$
46.57
Granted
64,063
63.58
Cancelled
(2,307)
23.73
Issued
(177,163)
49.23
$
Outstanding at December 31, 2019
991,908
$
47.24
At December 31, 2019, all outstanding restricted
stock and restricted stock units were fully vested
and there
was
no
remaining compensation cost to be recorded.
The weighted-average grant date fair value of awards
granted during 2018 and 2017 was $
62.01
and $
48.87
, respectively.
The total fair value of awards issued
during 2018 and 2017 was $
million and $
million, respectively.
Note 19-Income Taxes
Income taxes charged to net income (loss) were:
Millions of Dollars
Income Taxes
Federal
Current
$
Deferred
(113)
(3,046)
Foreign
Current
2,545
3,273
1,729
Deferred
(323)
(166)
(510)
State and local
Current
Deferred
(8)
(96)
(125)
$
2,267
3,668
(1,822)
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
Deferred Tax Liabilities
PP&E and intangibles
$
8,660
8,004
Inventory
Deferred state income tax
-
Other
Total deferred tax liabilities
8,929
8,281
Deferred Tax Assets
Benefit plan accruals
Asset retirement obligations and accrued environmental
costs
2,339
2,891
Investments in joint ventures
1,722
Other financial accruals and deferrals
Loss and credit carryforwards
8,968
2,378
Other
Total deferred tax assets
14,693
6,742
Less: valuation allowance
(10,214)
(3,040)
Net deferred tax assets
4,479
3,702
Net deferred tax liabilities
$
4,450
4,579
At December 31, 2019, noncurrent assets and liabilities
included deferred taxes of $
million and
$
4,634
million, respectively.
At December 31, 2018, noncurrent assets and liabilities
included deferred taxes
of $
million and $
5,021
million, respectively.
At December 31, 2019, the components of
our loss and credit carryforwards before and
after consideration of
the applicable valuation allowances were:
Millions of Dollars
Net Deferred
Expiration of
Gross Deferred
Tax Asset After
Net Deferred
Tax Asset
Valuation Allowance
Tax Asset
U.S. foreign tax credits
$
7,696
U.S. general business credits
2036-2038
U.S. capital loss
State net operating losses and tax credits
Various
Foreign net operating losses and tax credits
Post 2025
$
8,968
Valuation
allowances have been established to reduce
deferred tax assets to an amount that will,
more likely
than not, be realized.
During 2019, valuation allowances increased a total
of $
7,174
million.
The increase
primarily relates to deferred tax assets recognized
during 2019 as a result of the finalization of rules
related to
the U.S. Tax Cuts and Jobs Act (Tax Legislation including ongoing issuance of tax regulations related to such
legislation), as further discussed below.
Based on our historical taxable income, expectations
for the future,
and available tax-planning strategies, management
expects deferred tax assets, net of valuation
allowance, will
primarily be realized as offsets to reversing deferred tax
liabilities.
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 $
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, 2019, unremitted income
considered to be permanently reinvested in
certain foreign
subsidiaries and foreign corporate joint ventures
totaled approximately $
4,196
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
$
million.
The following table shows a reconciliation
of the beginning and ending unrecognized tax
benefits for 2019,
2018 and 2017:
Millions of Dollars
Balance at January 1
$
1,081
Additions based on tax positions related to the current
year
Additions for tax positions of prior years
Reductions for tax positions of prior years
(22)
(73)
(129)
Settlements
(9)
(35)
(5)
Lapse of statute
(2)
(4)
(86)
Balance at December 31
$
1,177
1,081
Included in the balance of unrecognized tax benefits
for 2019, 2018 and 2017 were $
1,100
million,
$
1,081
million and $
million, respectively, which, if recognized, would impact our effective tax rate.
The
balance of the unrecognized tax benefits increased
in 2019 mainly due to the treatment of our
PDVSA
settlement. The balance of the unrecognized tax
benefits increased in 2018 mainly due to the
treatment of
distributions from certain foreign subsidiaries.
The balance of unrecognized tax benefits
increased in 2017
mainly due to the recognition of a U.S. worthless securities
deduction that we do not believe will generate a
cash tax benefit.
See Note 13-Contingencies and Commitments,
for more information on the PDVSA
settlement.
At December 31, 2019, 2018 and 2017, accrued liabilities
for interest and penalties totaled $
million,
$
million and $
million, respectively, net of accrued income taxes.
Interest and penalties resulted in a
benefit to earnings of $
million in 2019, a benefit to earnings
of $
million in 2018, and
no
impact to earnings
in 2017.
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:
U.K. (2015), Canada (2014), U.S. (2014)
and Norway (2018).
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.
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.
The amounts of U.S. and foreign income (loss)
before income taxes, with a reconciliation of tax
at the federal
statutory rate with the provision for income taxes,
were:
Millions of Dollars
Percent of Pre-Tax Income (Loss)
Income (loss) before income taxes
United States
$
4,704
2,867
(5,250)
49.4
%
28.7
200.8
Foreign
4,820
7,106
2,635
50.6
71.3
(100.8)
$
9,524
9,973
(2,615)
100.0
%
100.0
100.0
Federal statutory income tax
$
2,000
2,095
(915)
21.0
%
21.0
35.0
Non-U.S. effective tax rates
1,399
1,766
14.7
17.7
(23.9)
Tax Legislation
-
(10)
(852)
-
(0.1)
32.6
Canada disposition
-
-
(1,277)
-
-
48.8
U.K. disposition
(732)
(150)
-
(7.7)
(1.5)
-
Recovery of outside basis
(77)
(21)
(962)
(0.8)
(0.2)
36.8
Adjustment to tax reserves
(4)
0.1
-
(33.7)
Adjustment to valuation allowance
(225)
(26)
-
(2.4)
(0.3)
-
APLNG impairment
-
-
-
-
(31.9)
State income tax
(84)
1.3
1.4
3.2
Malaysia Deepwater Incentive
(164)
-
-
(1.7)
-
-
Enhanced oil recovery credit
(27)
(99)
(68)
(0.3)
(1.0)
2.6
Other
(39)
(18)
(4)
(0.4)
(0.2)
0.2
$
2,267
3,668
(1,822)
23.8
%
36.8
69.7
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 $
million. The disposition generated a U.S. capital
loss of approximately $
2.1
billion which has generated a U.S.
tax benefit of approximately $
million. The remaining U.S. capital loss
has been recorded as a deferred tax
asset fully offset with a valuation allowance.
See Note 5-Asset Acquisitions and Dispositions,
for additional
information on the disposition.
During the third quarter of 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 $
million.
The decrease in the effective tax rate for 2018 was primarily
due to the impact of the Clair Field disposition
in
the U.K. and our overall income position, partially
offset by our mix of income among taxing jurisdictions.
Our effective tax rate for 2018 was favorably impacted
by the sale of a U.K. subsidiary to BP.
The subsidiary
held 16.5 percent of our 24 percent interest
in the BP-operated Clair Field in the U.K.
The disposition
generated a before-tax gain of $
million with no associated tax cost.
See Note 5-Asset Acquisitions and
Dispositions,
for additional information on the disposition.
Tax Legislation was enacted in the U.S. on December 22, 2017, reducing the
U.S. federal corporate income tax
rate to 21 percent from 35 percent, requiring companies
to pay a one-time transition tax on earnings of certain
foreign subsidiaries that were previously tax deferred
and creating new taxes on certain foreign-sourced
earnings.
SAB 118 measurement period
We applied the guidance in Staff Accounting Bulletin No. 118 when accounting for the enactment-date effects
of Tax Legislation in 2017 and throughout 2018.
At December 31, 2017, we had not completed
our
accounting for all the enactment-date income
tax effects of Tax Legislation under ASC 740, Income Taxes, for
the remeasurement of deferred tax assets and liabilities
and the one-time transition tax.
As of December 31,
2018, we had completed our accounting for all the
enactment-date income tax effects of Tax Legislation.
As
further discussed below, during 2018, we recognized adjustments of $
million to the provisional amounts
recorded at December 31, 2017, and included these
adjustments as a component
of income tax provision.
Provisional Amounts-Foreign tax effects
The one-time transition tax is based on our total
post-1986 earnings, the tax on which we previously
deferred
from U.S. income taxes under U.S. law.
We estimated at December 31, 2017, that we would not incur a one-
time transition tax.
Upon further analyses of Tax Legislation and Notices and regulations issued and proposed
by the U.S. Department of the Treasury and the Internal Revenue
Service, we finalized our calculations of the
transition tax liability during 2018.
Based upon this analysis, we did not incur a
one-time transition tax.
As a result of the Tax Legislation, we removed the indefinite reinvestment
assertion on one of our foreign
subsidiaries and recorded a tax expense of $
million in the fourth quarter of 2017.
Deferred tax assets and liabilities
As of December 31, 2017, we remeasured certain deferred
tax assets and liabilities based on the rates at
which
they were expected to reverse in the future (which
was generally 21 percent), by recording a provisional
amount of $
million.
Upon further analysis of certain aspects of
Tax Legislation and refinement of our
calculations during the 12 months ended December
31, 2018, we adjusted our provisional amount by
$
million, which is included as a component of income
tax expense.
Global intangible low-taxed income (GILTI)
We have elected to account for GILTI
in the year the tax is incurred.
For 2019 and 2018,
the current-year U.S.
income tax impact related to GILTI activities is immaterial.
Our effective tax rate in 2017 was favorably impacted
by a tax benefit of $
1,277
million related to the Canada
disposition.
This tax benefit was primarily associated with
a deferred tax recovery related to the Canadian
capital gains exclusion component of the 2017
Canada disposition and the recognition
of previously
unrealizable Canadian capital asset tax basis.
The Canada disposition, along with the
associated restructuring
of our Canadian operations, may generate an additional
tax benefit of $
million.
However, since we
believe it is not likely we will receive a corresponding
cash tax savings, this $
million benefit has been
offset by a full tax reserve.
See Note 5-Asset Acquisitions and Dispositions
for additional information on our
Canada disposition.
The impairment of our APLNG investment in the
second quarter of 2017 did not generate
a tax benefit.
See
the “APLNG” section of Note 6-Investments,
Loans and Long-Term Receivables, for information on the
impairment of our APLNG investment.
Certain operating losses in jurisdictions outside
of the U.S.
only yield a tax benefit in the U.S. as a worthless
security deduction.
For 2019, 2018 and 2017, before consideration
of unrecorded tax benefits discussed above,
the amount of the tax benefit was $
million, $
million and $
million, respectively.
Note 20-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
Loss on
Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
December 31, 2016
$
(547)
-
(5,646)
(6,193)
Other comprehensive income (loss)
(58)
December 31, 2017
(400)
(58)
(5,060)
(5,518)
Other comprehensive income (loss)
-
(642)
(603)
Cumulative effect of adopting ASU No. 2016-01*
-
-
December 31, 2018
(361)
-
(5,702)
(6,063)
Other comprehensive income
-
Cumulative effect of adopting ASU No. 2018-02**
(40)
-
-
(40)
December 31, 2019
$
(350)
-
(5,007)
(5,357)
*We adopted ASU No. 2016-01, "Recognition and Measurement of Financial Assets and Liabilities," beginning
January 1, 2018.
**See Note 2
-
Changes in Accounting Principles for additional information.
During 2019, we recognized $
million of foreign currency translation adjustments
related to the completion
of our sale of two ConocoPhillips U.K. subsidiaries.
For additional information related to this
disposition, see
Note 5-Asset Acquisitions and Dispositions.
There were no items within accumulated other comprehensive
loss related to noncontrolling interests.
The following table summarizes reclassifications
out of accumulated other comprehensive loss during
the years
ended December 31:
Millions of Dollars
Defined Benefit Plans
$
Above amounts are included in the computation of net periodic benefit cost
and
are presented net of tax expense of:
$
See Note 18-Employee Benefit Plans, for additional information.
Note 21-Cash Flow Information
Millions of Dollars
Noncash Investing Activities
Increase (decrease) in PP&E related to an increase
(decrease) in asset
retirement obligations
$
(37)
Increase (decrease) in assets and liabilities
acquired in a nonmonetary
exchange*
Accounts receivable
-
(44)
-
Inventories
-
-
Investments and long-term receivables
-
-
PP&E
-
1,907
-
Other long-term assets
-
(9)
-
Accounts payable
-
-
Accrued income and other taxes
-
-
Cash Payments
Interest
$
1,163
Income taxes
2,905
2,976
1,168
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(4,902)
(1,953)
(6,617)
Short-term investments sold
2,138
3,573
4,827
Investments and long-term receivables purchased
(146)
-
-
$
(2,910)
1,620
(1,790)
*See Note 5-Asset Acquisitions and Dispositions.
The following items are included in the “Cash
Flows from Operating Activities” section
of our consolidated
cash flows.
We collected $
million and $
million in 2019 and 2018, respectively, from PDVSA under a settlement
agreement related to an award issued by the ICC
Tribunal in 2018.
We collected $
million and $
million
from Ecuador in 2018 and 2017, respectively, as installment payments related
to an agreement reached with
Ecuador in 2017.
For more information on these settlements,
see Note 13-Contingencies and Commitments.
In 2019, we made a $
million contribution to our U.K. pension plan.
We made discretionary payments to
our domestic qualified pension plan of $
million and $
million in 2018 and 2017, respectively.
In 2017, we recognized a $
million adverse cash impact from the settlement
of cross-currency swap
transactions.
Note 22-Other Financial Information
Millions of Dollars
Interest and Debt Expense
Incurred
Debt
$
1,114
Other
1,217
Capitalized
(57)
(170)
(119)
Expensed
$
1,098
Other Income
Interest income
$
Unrealized gains (losses) on Cenovus Energy common shares*
(437)
-
Other, net
$
1,358
*See Note 7-Investment in Cenovus Energy, for additional information.
Research and Development Expenditures
-expensed
$
Shipping and Handling Costs
$
1,008
1,075
1,050
Foreign Currency Transaction (Gains) Losses
-after-tax
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
(11)
Europe and North Africa
-
(26)
Asia Pacific and Middle East
Other International
-
Corporate and Other
(3)
$
(13)
Millions of Dollars
Properties, Plants and Equipment
Proved properties
$
88,284
*
100,657
Unproved properties
3,980
*
4,662
Other
5,482
5,278
Gross properties, plants and equipment
97,746
110,597
Less: Accumulated depreciation, depletion and amortization
(55,477)
*
(64,899)
Net properties, plants and equipment
$
42,269
45,698
*Excludes assets classified as held for sale at December 31,
2019.
See Note 5
-
Asset Acquisitions and Dispositions, for additional information.
Note 23-Related Party Transactions
Our related parties primarily include equity method
investments and certain trusts for the benefit
of employees.
Significant transactions with our equity affiliates
were:
Millions of Dollars
Operating revenues and other income
$
Purchases
Operating expenses and selling, general and administrative
expenses
Net interest (income) expense*
(13)
(14)
(13)
*We paid interest to, or received interest from,
various affiliates.
See Note 6-Investments, Loans and Long-Term Receivables, for additional
information on loans to affiliated companies.
The table above includes transactions with the
FCCL Partnership through the date of the
sale.
See Note 6-
Investments, Loans and Long-Term Receivables, for additional information.
Note 24-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
Revenue from contracts with customers
$
26,106
28,098
20,525
Revenue from contracts outside the scope of ASC
Topic 606
Physical contracts meeting the definition of a derivative
6,558
8,218
8,669
Financial derivative contracts
(97)
(88)
Consolidated sales and other operating revenues
$
32,567
36,417
29,106
Revenues from contracts outside the scope of ASC
Topic 606 relate primarily to physical gas contracts at
market prices which qualify as derivatives accounted
for under ASC Topic 815, “Derivatives and Hedging,”
and for which we have not elected NPNS.
There is no significant difference in contractual
terms or the policy
for recognition of revenue from these contracts
and those within the scope of ASC Topic 606.
The following
disaggregation of revenues is provided in conjunction
with Note 25-Segment Disclosures and Related
Information:
Millions of Dollars
Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
$
4,989
6,358
6,302
Canada
Europe and North Africa
1,231
1,503
Physical contracts meeting the definition of a derivative
$
6,558
8,218
8,669
Millions of Dollars
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
1,112
Natural gas
5,313
6,734
7,811
Other
Physical contracts meeting the definition of a derivative
$
6,558
8,218
8,669
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, 2019, the “Accounts and
notes receivable” line on our consolidated
balance sheet included
trade receivables of $
2,372
million compared with $
2,889
million at December 31, 2018, and included both
contracts with customers within the scope of ASC
Topic 606 and those that are outside the scope of ASC
Topic 606.
We typically receive payment within 30 days or less (depending on the terms of the invoice) once
delivery is made.
Revenues that are outside the scope of ASC Topic 606 relate primarily to
physical gas sales
contracts at market prices for which we do not
elect NPNS and are therefore accounted for
as a derivative
under ASC Topic 815.
There is little distinction in the nature
of the customer or credit quality of trade
receivables associated with gas sold under contracts
for which NPNS has not been elected
compared 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, 2018
$
Contractual payments received
Revenue recognized
(199)
At December 31, 2019
$
We expect to recognize the contract liabilities as of December 31, 2019, as revenue during 2021 and 2022.
Note 25-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 and
North Africa, Asia Pacific and Middle East,
and Other
International.
Corporate and Other represents 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-Accounting Policies.
Intersegment sales are at
prices that approximate market.
Analysis of Results by Operating Segment
Millions of Dollars
Sales and Other Operating Revenues
Alaska
$
5,483
5,740
4,224
Lower 48
15,514
17,029
12,968
Intersegment eliminations
(46)
(40)
(4)
Lower 48
15,468
16,989
12,964
Canada
2,910
3,184
3,178
Intersegment eliminations
(1,141)
(1,160)
(559)
Canada
1,769
2,024
2,619
Europe and North Africa
5,101
6,635
5,181
Asia Pacific and Middle East
4,525
4,861
4,014
Other International
-
-
-
Corporate and Other
Consolidated sales and other operating revenues
$
32,567
36,417
29,106
Depreciation, Depletion, Amortization and Impairments
Alaska
$
1,026
Lower 48
3,224
2,370
6,693
Canada
Europe and North Africa
1,041
1,313
Asia Pacific and Middle East
1,285
1,382
3,819
Other International
-
-
-
Corporate and Other
Consolidated depreciation, depletion, amortization
and impairments
$
6,495
5,983
13,446
The market for our products is large and diverse, therefore,
our sales and other operating revenues are not
dependent upon any single customer.
Millions of Dollars
Equity in Earnings of Affiliates
Alaska
$
Lower 48
(159)
Canada
-
-
Europe and North Africa
Asia Pacific and Middle East
1,051
Other International
-
-
-
Corporate and Other
-
-
-
Consolidated equity in earnings of affiliates
$
1,074
Income Taxes
Alaska
$
(689)
Lower 48
(2,453)
Canada
(43)
(96)
(616)
Europe and North Africa
1,435
2,265
1,165
Asia Pacific and Middle East
Other International
Corporate and Other
(233)
(103)
Consolidated income taxes
$
2,267
3,668
(1,822)
Net Income (Loss) Attributable to ConocoPhillips
Alaska
$
1,520
1,814
1,466
Lower 48
1,747
(2,371)
Canada
2,564
Europe and North Africa
2,724
1,866
Asia Pacific and Middle East
1,929
2,070
(1,098)
Other International
Corporate and Other
(1,667)
(2,136)
Consolidated net income (loss) attributable
to ConocoPhillips
$
7,189
6,257
(855)
Investments in and Advances to Affiliates
Alaska
$
Lower 48
Canada
-
-
-
Europe and North Africa
Asia Pacific and Middle East
8,281
8,821
9,077
Other International
-
-
-
Corporate and Other
-
-
-
Consolidated investments in and advances to affiliates
$
8,453
9,340
9,590
Millions of Dollars
Total Assets
Alaska
$
15,453
14,648
12,108
Lower 48
14,425
14,888
14,632
Canada
6,350
5,748
6,214
Europe and North Africa
8,121
9,883
11,870
Asia Pacific and Middle East
14,716
16,151
16,985
Other International
Corporate and Other
11,164
8,573
11,456
Consolidated total assets
$
70,514
69,980
73,362
Capital Expenditures and Investments
Alaska
$
1,513
1,298
Lower 48
3,394
3,184
2,136
Canada
Europe and North Africa
Asia Pacific and Middle East
Other International
Corporate and Other
Consolidated capital expenditures and investments
$
6,636
6,750
4,591
Interest Income and Expense
Interest income
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
-
-
-
Europe and North Africa
Asia Pacific and Middle East
Other International
-
-
-
Corporate and Other
Interest and debt expense
Corporate and Other
$
1,098
Sales and Other Operating Revenues by
Product
Crude oil
$
18,482
19,571
13,260
Natural gas
8,715
10,720
10,773
Natural gas liquids
1,114
1,102
Other*
4,556
5,012
3,971
Consolidated sales and other operating revenues
by product
$
32,567
36,417
29,106
*Includes LNG and bitumen.
Geographic Information
Millions of Dollars
Sales and Other Operating Revenues
(1)
Long-Lived Assets
(2)
United States
(3)
$
21,159
22,740
17,204
26,566
26,838
23,623
Australia and Timor-Leste
(4)
1,647
1,798
1,448
7,228
9,301
9,657
Canada
1,769
2,024
2,619
5,769
5,333
5,613
China
1,447
1,380
1,275
Indonesia
Libya
1,103
1,142
Malaysia
1,230
1,346
1,103
1,871
2,327
2,736
Norway
2,349
2,886
2,348
5,258
5,582
6,154
United Kingdom
1,649
2,606
2,248
1,583
3,335
Other foreign countries
1,308
1,346
1,423
Worldwide consolidated
$
32,567
36,417
29,106
50,722
55,038
55,273
(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) Long-lived assets do not include $
million of net PP&E associated with assets held
for sale as of December 31,
2019.
See Note 5-Acquisitions and Dispositions, for additional
information.
(4) Long-lived assets do not include $
1,236
million of net PP&E associated with assets
held for sale as of December
31, 2019.
See Note 5-Acquisitions and Dispositions, for additional
information.
Note 26-New Accounting Standards
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on
Financial Instruments”
(ASU No. 2016-13), which sets forth the current
expected credit loss model, a new forward-looking
impairment model for certain financial instruments
based on expected losses rather than incurred losses.
The
ASU is effective for interim and annual periods beginning
after December 15, 2019.
Entities are required to
adopt ASU No. 2016-13 using a modified retrospective
approach, subject to certain limited exceptions.
The
impact
of adopting this ASU is not expected to be material
to our financial statements.
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, and Africa. Period end proved
reserves, capitalized costs, wells and acreage
include held-
for-sale assets at December 31, 2019. See Note 5-Asset
Acquisitions and Dispositions, in the Notes to
Consolidated Financial Statements, for additional
information on held-for-sale assets.
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, 2019, approximately
6 percent of our total
proved reserves were under PSCs, located in
our Asia Pacific/Middle East geographic
reporting area, and 6
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.
We have a companywide, 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 2019, our processes and controls used
to assess over 90 percent of proved reserves
as of December 31,
2019, 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, 2019, 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.
Proved Reserves
Years Ended
Crude Oil
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2016
1,343
2,047
Revisions
-
Improved recovery
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
Production
(60)
(64)
(124)
(1)
(45)
(34)
(7)
(211)
Sales
-
(10)
(10)
(12)
-
-
-
(22)
End of 2017
1,644
2,322
Revisions
(90)
(18)
Improved recovery
-
-
-
-
-
Purchases
-
-
-
-
Extensions and discoveries
-
Production
(59)
(82)
(141)
(1)
(40)
(33)
(13)
(228)
Sales
-
(12)
(12)
-
(36)
-
-
(48)
End of 2018
1,233
1,936
2,533
Revisions
(36)
(1)
(5)
Improved recovery
-
-
-
-
-
Purchases
-
-
-
-
-
Extensions and discoveries
-
-
Production
(74)
(95)
(169)
-
(36)
(31)
(14)
(250)
Sales
-
(2)
(2)
-
(30)
-
-
(32)
End of 2019
1,231
2,028
2,562
Equity affiliates
End of 2016
-
-
-
-
-
-
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
Total
company
End of 2016
1,343
2,135
End of 2017
1,644
2,405
End of 2018
1,233
1,936
2,611
End of 2019
1,231
2,028
2,635
Years Ended
Crude Oil
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2016
1,003
1,509
End of 2017
1,143
1,651
End of 2018
1,058
1,404
1,896
End of 2019
1,048
1,382
1,809
Equity affiliates
End of 2016
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
Undeveloped
Consolidated operations
End of 2016
-
-
End of 2017
-
-
End of 2018
End of 2019
Equity affiliates
End of 2016
-
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
-
Notable changes in proved crude oil reserves
in the three years ended December 31, 2019,
included:
●
Revisions
: 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.
In 2018, downward revisions in Lower 48 were
primarily due to changes in development
timing for specific well
locations from the unconventional plays and are
more than offset by increases in planned well locations
in the
unconventional plays in the extensions and discoveries
category.
Downward revisions in Lower 48 due to development
timing were partially offset by higher prices. Revisions in
Alaska, Europe and Asia Pacific/Middle
East were primarily
due to higher prices.
In 2017, revisions in Alaska, Lower 48, Europe
and Asia Pacific/Middle East were primarily
due to higher prices.
●
Purchases:
In 2018, Alaska purchases were due to the
Greater Kuparuk Area and Western North Slope acquisitions.
●
Extensions and discoveries
: 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.
In 2018, extensions and discoveries in Lower 48
were primarily due to changes in the development
strategy to add
specific well locations from the unconventional plays.
Extensions and discoveries in Alaska
were driven by drilling
success in Western North Slope.
In 2017, extensions and discoveries in Lower 48
were primarily due to continued drilling success
in the Permian
Unconventional, Eagle Ford and Bakken.
●
Sales
: In 2019, Europe sales represent the disposition
of the U.K. assets. In 2018, Europe sales
were due to the
disposition of a subsidiary that held 16.5 percent
of our 24 percent interest in the Clair Field
in the U.K.
In 2017,
Canada sales were due to the disposition of
a majority of our western Canada assets.
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Total
Developed and Undeveloped
Consolidated operations
End of 2016
Revisions
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
Production
(5)
(24)
(29)
(3)
(3)
(2)
(37)
Sales
-
(130)
(130)
(44)
-
-
(174)
End of 2017
Revisions
(25)
(20)
-
(1)
(20)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
Production
(5)
(25)
(30)
-
(3)
(1)
(34)
Sales
-
(21)
(21)
-
-
-
(21)
End of 2018
Revisions
(1)
(11)
(12)
-
(1)
(10)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
Production
(5)
(28)
(33)
-
(3)
(1)
(37)
Sales
-
-
-
-
(4)
-
(4)
End of 2019
Equity affiliates
End of 2016
-
-
-
-
-
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(2)
(2)
Sales
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
Total
company
End of 2016
End of 2017
End of 2018
End of 2019
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Total
Developed
Consolidated operations
End of 2016
End of 2017
End of 2018
-
End of 2019
Equity affiliates
End of 2016
-
-
-
-
-
End of 2017
-
-
-
-
-
End of 2018
-
-
-
-
-
End of 2019
-
-
-
-
-
Undeveloped
Consolidated operations
End of 2016
-
-
End of 2017
-
-
End of 2018
-
-
End of 2019
-
-
Equity affiliates
End of 2016
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
Notable changes in proved NGL reserves in the three
years ended December 31, 2019,
included:
●
Revisions
: 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.
In 2018, downward revisions in Lower 48 were
primarily due to changes in development
timing for specific well
locations from the unconventional plays and are
more than offset by increases in planned well locations
in the
unconventional plays in the extensions and discoveries
category.
In 2017, revisions in Lower 48 were primarily
due to higher prices.
●
Extensions and discoveries
: 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 2018, extensions and discoveries in Lower 48
were primarily due to changes in the development
strategy to add
specific well locations from the unconventional plays.
In 2017, extensions and discoveries in Lower 48
were primarily due to continued drilling success
in the Permian
Unconventional, Eagle Ford and Bakken.
●
Sales
: In 2019, Europe sales represent the disposition
of the U.K. assets.
In 2018, Lower 48 sales were primarily
due to
the disposition of our interests in the Barnett.
In 2017, Lower 48 sales were due to the
disposition of our interests in the
San Juan Basin and Panhandle assets, while Canada
sales were due to the disposition of a majority
of our western
Canada assets.
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2016
2,102
4,714
6,816
1,037
1,238
1,526
10,844
Revisions
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
Production
(71)
(338)
(409)
(71)
(188)
(267)
(3)
(938)
Sales
-
(2,885)
(2,885)
(966)
-
-
-
(3,851)
End of 2017
2,320
2,533
4,853
1,217
1,298
7,603
Revisions
(283)
(133)
-
(34)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
Extensions and discoveries
-
Production
(71)
(237)
(308)
(5)
(188)
(246)
(10)
(757)
Sales
-
(223)
(223)
-
(13)
-
-
(236)
End of 2018
2,736
2,318
5,054
1,212
1,079
7,585
Revisions
(113)
(83)
(2)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
Extensions and discoveries
-
-
Production
(85)
(252)
(337)
(4)
(178)
(250)
(11)
(780)
Sales
-
(7)
(7)
-
(298)
-
-
(305)
End of 2019
2,688
2,431
5,119
7,259
Equity affiliates
End of 2016
-
-
-
-
-
4,381
-
4,381
Revisions
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
Production
-
-
-
-
-
(374)
-
(374)
Sales
-
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
4,303
-
4,303
Revisions
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
Production
-
-
-
-
-
(381)
-
(381)
Sales
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
4,564
-
4,564
Revisions
-
-
-
-
-
(7)
-
(7)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
Production
-
-
-
-
-
(388)
-
(388)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
4,421
-
4,421
Total
company
End of 2016
2,102
4,714
6,816
1,037
1,238
5,907
15,225
End of 2017
2,320
2,533
4,853
1,217
5,601
11,906
End of 2018
2,736
2,318
5,054
1,212
5,643
12,149
End of 2019
2,688
2,431
5,119
5,398
11,680
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2016
2,094
4,199
6,293
1,031
1,188
9,737
End of 2017
2,310
1,597
3,907
6,084
End of 2018
2,720
1,427
4,147
1,052
6,188
End of 2019
2,601
1,398
3,999
5,793
Equity affiliates
End of 2016
-
-
-
-
-
4,110
-
4,110
End of 2017
-
-
-
-
-
4,044
-
4,044
End of 2018
-
-
-
-
-
4,059
-
4,059
End of 2019
-
-
-
-
-
3,898
-
3,898
Undeveloped
Consolidated operations
End of 2016
-
1,107
End of 2017
-
-
1,519
End of 2018
-
1,397
End of 2019
1,033
1,120
-
1,466
Equity affiliates
End of 2016
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
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 3,141 Bcf,
3,131 Bcf, and 3,825 Bcf as of December 31,
2019, 2018 and 2017, 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, 2019, included:
●
Revisions
: 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.
In 2018, downward revisions in Lower 48 were
primarily due to changes in development
timing for specific well
locations from the unconventional plays and are
more than offset by increases in planned well locations
in the
unconventional plays in the extensions and discoveries
category.
Downward revisions in Lower 48 due to development
timing were partially offset by higher prices.
Revisions in Alaska, Canada, Europe and our equity
affiliates in Asia
Pacific/Middle East were primarily due to higher prices.
In 2017, revisions in Alaska, Lower 48 and
Europe were primarily due to higher prices.
●
Purchases
: In 2018, Alaska purchases were due to
the Greater Kuparuk Area and Western North Slope acquisitions.
●
Extensions and discoveries
: 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.
In 2018, extensions and discoveries in Lower 48
were primarily due to changes in the development
strategy to add
specific well locations from the unconventional plays.
Extensions and discoveries in Canada,
Europe and our equity
affiliates in Asia Pacific/Middle East were primarily
driven by ongoing drilling successes in Montney, Norway and
APLNG, respectively.
In 2017, extensions and discoveries in Lower 48
were primarily due to continued drilling success
in the Permian
Unconventional, Eagle Ford and Bakken.
●
Sales
: In 2019, Europe
sales represent the disposition of the U.K.
assets.
In 2018, Lower 48 sales were primarily
due to
the disposition of our interest in Barnett.
In 2017, Lower 48 sales were due to the disposition
of our interests in the San
Juan Basin and Panhandle assets, while Canada sales
were due to the disposition of a majority
of our western Canada
assets.
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed and Undeveloped
Consolidated operations
End of 2016
Revisions
Improved recovery
-
Purchases
-
Extensions and discoveries
Production
(21)
Sales
-
End of 2017
Revisions
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(24)
Sales
-
End of 2018
Revisions
Improved recovery
-
Purchases
-
Extensions and discoveries
Production
(22)
Sales
-
End of 2019
Equity affiliates
End of 2016
1,089
Revisions
-
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(23)
Sales
(1,066)
End of 2017
-
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2018
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2019
Total
company
End of 2016
1,248
End of 2017
End of 2018
End of 2019
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed
Consolidated operations
End of 2016
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
-
End of 2018
-
End of 2019
-
Undeveloped
Consolidated operations
End of 2016
-
End of 2017
End of 2018
End of 2019
Equity affiliates
End of 2016
End of 2017
-
End of 2018
-
End of 2019
-
Notable changes in proved bitumen reserves
in the three years ended December 31, 2019,
included:
●
Revisions
: 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.
In 2018 and 2017,
revisions were primarily due to higher
prices at Surmont.
●
Extensions and discoveries
: 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.
In 2017, extensions and discoveries were primarily
due to higher prices at Surmont, which allowed
undeveloped reserves previously de-booked due
to low prices to be recognized.
●
Sales
: In 2017, sales were due to the disposition of
our 50 percent interest in the FCCL Partnership
in
Canada.
Years Ended
Total Proved
Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2016
1,294
1,570
2,864
4,470
Revisions
-
Improved recovery
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
Production
(77)
(144)
(221)
(37)
(79)
(81)
(8)
(426)
Sales
-
(621)
(621)
(217)
-
-
-
(838)
End of 2017
1,430
1,353
2,783
4,193
Revisions
(161)
(59)
Improved recovery
-
-
-
-
-
Purchases
-
-
-
-
Extensions and discoveries
-
Production
(76)
(146)
(222)
(25)
(75)
(75)
(15)
(412)
Sales
-
(70)
(70)
-
(38)
-
-
(108)
End of 2018
1,795
1,312
3,107
4,383
Revisions
(67)
(23)
Improved recovery
-
-
-
-
-
Purchases
-
-
-
-
-
Extensions and discoveries
-
-
Production
(93)
(165)
(258)
(23)
(68)
(74)
(16)
(439)
Sales
-
(3)
(3)
-
(85)
-
-
(88)
End of 2019
1,779
1,447
3,226
4,414
Equity affiliates
End of 2016
-
-
-
1,089
-
-
1,954
Revisions
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
Production
-
-
-
(23)
-
(69)
-
(92)
Sales
-
-
-
(1,066)
-
-
-
(1,066)
End of 2017
-
-
-
-
-
-
Revisions
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
Production
-
-
-
-
-
(71)
-
(71)
Sales
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
Revisions
-
-
-
-
-
(1)
-
(1)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
Total
company
End of 2016
1,294
1,570
2,864
1,482
1,309
6,424
End of 2017
1,430
1,353
2,783
1,251
5,038
End of 2018
1,795
1,312
3,107
1,222
5,263
End of 2019
1,779
1,447
3,226
1,146
5,262
Years Ended
Total Proved
Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2016
1,203
1,165
2,368
3,674
End of 2017
1,319
2,001
3,045
End of 2018
1,617
2,298
3,305
End of 2019
1,582
2,248
3,174
Equity affiliates
End of 2016
-
-
-
-
-
1,142
End of 2017
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
Undeveloped
Consolidated operations
End of 2016
-
End of 2017
-
1,148
End of 2018
1,078
End of 2019
1,240
Equity affiliates
End of 2016
-
-
-
-
-
End of 2017
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
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
We had 1,327 MMBOE of PUDs at year-end 2019,
compared with 1,162 MMBOE at year-end 2018.
The following table
shows changes in total proved undeveloped reserves
for 2019:
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
End of 2018
1,162
Transfers to proved developed
(286)
Revisions
(5)
Improved recovery
Purchases
Extensions and discoveries
Sales
(20)
End of 2019
1,327
Transfers to proved developed reserves were driven by the ongoing
development of our assets. Approximately half
of the
transfers were from the development of our
Lower 48 unconventional plays. The remainder
of transfers were from development
across the Asia Pacific/Middle East, Alaska, Europe
and Canada regions.
Downward revisions were driven by changes in
development timing of 166 MMBOE primarily
in Lower 48 and Canada,
largely offset by upward revisions for infill drilling of 147 MMBOE
primarily in Lower 48, Europe, Alaska and
Africa.
Extensions and discoveries were largely driven by an addition
of 358 MMBOE in Lower 48 for the continued development
of
unconventional plays. The remaining extensions
and discoveries were driven by the continued
development planned in Alaska,
Canada and Asia Pacific/Middle East.
Sales were due to the disposition of the U.K.
assets.
At December 31, 2019, our PUDs represented
25 percent of total proved reserves, compared
with 22 percent at December 31,
2018.
Costs incurred for the year ended December
31, 2019, relating to the development of PUDs
were $4.6 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 2019, more than 90 percent of total
PUDs were under development or scheduled for
development within five
years of initial disclosure. The remainder are to
be developed as parts of major projects ongoing
in our Canada, Asia
Pacific/Middle East and Europe regions.
All major development areas are currently producing
and are expected to have PUDs
convert to proved developed over time.
Of our total PUDs at year-end 2019, 81 percent are
in North America, and 95 percent of
these reserve volumes are planned for development
within five years of initial disclosure.
Results of Operations
The company’s results of operations from oil and gas activities
for the years 2019, 2018 and 2017 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 transportation 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.
Results of Operations
Year Ended
Millions of Dollars
December 31, 2019
Lower
Total
Asia Pacific/
Other
Alaska
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,883
6,356
11,239
3,207
3,032
-
19,106
Transfers
-
-
-
-
-
Transportation costs
(629)
-
(629)
-
-
(41)
-
-
(670)
Other revenues
1,785
2,449
Total revenues
4,319
6,434
10,753
4,992
3,452
1,020
21,338
Production costs excluding taxes
1,235
1,578
2,813
(8)
4,615
Taxes other than income taxes
(2)
Exploration expenses
Depreciation, depletion and
amortization
2,804
3,504
1,172
-
5,785
Impairments
-
-
-
-
Other related expenses
(12)
(38)
(42)
Accretion
-
-
1,929
2,547
3,207
1,426
8,520
Income tax provision (benefit)
(74)
2,406
Results of operations
$
1,485
1,956
2,616
6,114
Equity affiliates
Sales
$
-
-
-
-
-
-
-
Transfers
-
-
-
-
-
2,229
-
-
2,229
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
-
-
Total revenues
-
-
-
-
-
2,859
-
-
2,859
Production costs excluding taxes
-
-
-
-
-
-
-
Taxes other than income taxes
-
-
-
-
-
-
-
Exploration expenses
-
-
-
-
-
-
-
-
-
Depreciation, depletion and
amortization
-
-
-
-
-
-
-
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
-
-
Accretion
-
-
-
-
-
-
-
-
-
-
-
-
1,098
-
-
1,098
Income tax provision (benefit)
-
-
-
-
-
-
-
Results of operations
$
-
-
-
-
-
-
-
Year Ended
Millions of Dollars
December 31, 2018
Lower
Total
Asia Pacific/
Other
Alaska
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,816
6,573
11,389
4,449
3,177
-
20,547
Transfers
-
-
-
-
-
Transportation costs
(722)
-
(722)
-
-
(45)
-
-
(767)
Other revenues
1,997
Total revenues
4,434
6,786
11,220
5,186
3,683
1,060
22,327
Production costs excluding taxes
1,533
2,497
4,480
Taxes other than income taxes
-
Exploration expenses
(4)
Depreciation, depletion and
amortization
2,279
2,895
1,070
1,186
-
5,497
Impairments
(78)
-
-
Other related expenses
(62)
(19)
(1)
Accretion
-
-
2,365
2,188
4,553
(98)
3,132
1,679
10,642
Income tax provision (benefit)
(114)
1,354
(8)
3,726
Results of operations
$
1,946
1,722
3,668
1,778
6,916
Equity affiliates
Sales
$
-
-
-
-
-
-
-
Transfers
-
-
-
-
-
2,018
-
-
2,018
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
(6)
-
-
(6)
Total revenues
-
-
-
-
-
2,770
-
-
2,770
Production costs excluding taxes
-
-
-
-
-
-
-
Taxes other than income taxes
-
-
-
-
-
-
-
Exploration expenses
-
-
-
-
-
-
-
-
-
Depreciation, depletion and
amortization
-
-
-
-
-
-
-
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
(4)
-
-
(4)
Accretion
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Income tax provision (benefit)
-
-
-
-
-
-
-
Results of operations
$
-
-
-
-
-
-
-
Year Ended
Millions of Dollars
December 31, 2017
Lower
Total
Asia Pacific/
Other
Alaska
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
3,542
4,557
8,099
3,527
2,752
-
15,570
Transfers
-
-
-
-
-
Transportation costs
(706)
-
(706)
-
-
(80)
-
-
(786)
Other revenues
2,158
2,649
Total revenues
2,854
4,585
7,439
2,863
3,595
3,094
17,848
Production costs excluding taxes
1,607
2,554
(1)
4,537
Taxes other than income taxes
-
Exploration expenses
Depreciation, depletion and
amortization
2,685
3,415
1,234
1,283
-
6,386
Impairments
3,969
4,148
-
-
-
4,216
Other related expenses
(7)
-
Accretion
-
-
(4,703)
(4,108)
1,721
1,239
1,012
Income tax provision (benefit)
(669)
(2,401)
(3,070)
(651)
(2,217)
Results of operations
$
1,264
(2,302)
(1,038)
2,372
(22)
2,765
Equity affiliates
Sales
$
-
-
-
-
-
-
1,091
Transfers
-
-
-
-
-
1,398
-
-
1,398
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
-
-
Total revenues
-
-
-
-
1,961
-
-
2,494
Production costs excluding taxes
-
-
-
-
-
-
Taxes other than income taxes
-
-
-
-
-
-
Exploration expenses
-
-
-
-
1,699
-
-
1,700
Depreciation, depletion and
-
-
-
-
-
-
-
-
amortization
-
-
-
-
-
-
Impairments
-
-
-
-
-
1,717
-
-
1,717
Other related expenses
-
-
-
-
-
Accretion
-
-
-
-
-
-
-
-
-
-
(3,072)
-
(19)
(2,896)
Income tax provision (benefit)
-
-
-
-
(998)
-
(959)
Results of operations
$
-
-
-
-
(2,074)
-
(32)
(1,937)
Statistics
Net Production
Thousands of Barrels Daily
Crude Oil
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated
operations
Equity affiliates-
Asia Pacific/Middle East
Total company
Greater Prudhoe Area
(Alaska)*
Natural Gas Liquids
Consolidated operations
Alaska
Lower 48
United States
Canada
-
Europe
Asia Pacific/Middle East
Total consolidated
operations
Equity affiliates-
Asia Pacific/Middle East
Total company
Greater Prudhoe Area
(Alaska)*
Bitumen
Consolidated operations-
Canada
Equity affiliates-
Canada
Total company
Natural Gas
Millions of Cubic Feet Daily
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Total consolidated
operations
1,753
1,743
2,263
Equity affiliates-
Asia Pacific/Middle East
1,052
1,031
1,007
Total company
2,805
2,774
3,270
Greater Prudhoe Area
(Alaska)*
*At year-end 2019, the Greater Prudhoe Area in Alaska contained more than 15% of total proved reserves.
Average Sales
Prices
Crude Oil Per Barrel
Consolidated operations
Alaska
$
55.85
60.23
42.69
Lower 48
55.30
62.99
47.36
United States
55.54
61.75
45.01
Canada
40.87
48.73
43.69
Europe
65.12
70.98
54.04
Asia Pacific/Middle East
65.02
70.93
54.38
Africa
64.47
69.83
55.11
Total international
64.85
70.67
54.16
Total consolidated
operations
58.51
65.01
48.70
Equity affiliates
-Asia Pacific/Middle East
61.32
72.49
54.76
Total operations
58.57
65.17
48.84
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48
$
16.83
27.30
22.20
United States
16.85
27.30
22.20
Canada
19.87
43.70
21.51
Europe
29.37
36.87
34.07
Asia Pacific/Middle East
37.85
47.20
41.37
Total international
32.29
40.00
30.34
Total consolidated
operations
18.73
29.03
24.21
Equity affiliates
-Asia Pacific/Middle East
36.70
45.69
38.74
Total operations
20.09
30.48
25.22
Bitumen Per Barrel
Consolidated operations-
Canada
$
31.72
22.29
21.43
Equity affiliates-
Canada
23.83
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
$
3.19
2.48
2.72
Lower 48
2.12
2.82
2.73
United States
2.12
2.82
2.73
Canada
0.49
1.00
1.93
Europe
4.92
7.79
5.72
Asia Pacific/Middle East
5.73
5.95
4.66
Africa
4.87
4.84
3.53
Total international
5.35
6.64
4.64
Total consolidated
operations
4.19
5.33
3.87
Equity affiliates
-Asia Pacific/Middle East
6.29
6.06
4.27
Total operations
4.99
5.60
4.00
Average sales prices for Alaska crude oil and Asia Pacific/Middle East 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 Production
Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
$
15.52
14.20
14.26
Lower 48
9.59
10.58
11.03
United States
11.52
11.73
12.04
Canada
16.53
16.32
16.22
Europe
11.22
11.73
10.09
Asia Pacific/Middle East
8.74
9.03
7.31
Africa
4.46
4.14
5.74
Total international
10.26
10.72
9.99
Total consolidated operations
10.99
11.26
11.05
Equity affiliates
Canada
7.57
Asia Pacific/Middle East
4.68
4.56
5.26
Total equity affiliates
4.68
4.56
5.84
Average Production
Costs Per Barrel-Bitumen
Consolidated operations-
Canada
$
13.74
13.59
14.63
Equity affiliates-
Canada
18.74
Taxes
Other Than Income Taxes Per Barrel
of Oil Equivalent
Consolidated operations
Alaska
$
3.87
5.26
4.14
Lower 48
2.65
2.98
2.18
United States
3.05
3.71
2.80
Canada
0.78
0.82
0.89
Europe
0.48
0.45
0.42
Asia Pacific/Middle East
0.76
1.33
0.50
Africa
0.19
0.20
0.26
Total international
0.60
0.82
0.53
Total consolidated operations
2.03
2.37
1.70
Equity affiliates
Canada
0.30
Asia Pacific/Middle East
11.46
11.41
8.76
Total equity affiliates
11.46
11.41
6.64
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
8.80
9.07
10.99
Lower 48
17.03
15.73
18.44
United States
14.35
13.60
16.10
Canada
10.00
12.25
11.76
Europe
12.75
14.66
16.18
Asia Pacific/Middle East
16.55
16.58
16.58
Africa
2.36
2.21
2.09
Total international
12.99
14.06
14.96
Total consolidated operations
13.78
13.82
15.55
Equity affiliates
Canada
6.52
Asia Pacific/Middle East
8.09
9.09
8.94
Total equity affiliates
8.09
9.09
8.34
*Includes bitumen.
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, 2019,
2018 and 2017.
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
Exploratory
Consolidated operations
Alaska
-
-
-
-
Lower 48
United States
Canada
-
-
-
-
Europe
*
*
*
*
Asia Pacific/Middle East
-
Africa
-
-
-
-
*
-
Other areas
-
-
-
-
-
Total consolidated
operations
Equity affiliates
Asia Pacific/Middle East
-
-
Total equity affiliates
-
-
Development
Consolidated operations
Alaska
-
-
-
Lower 48
-
-
-
United States
-
-
-
Canada
-
-
-
Europe
-
-
-
Asia Pacific/Middle East
-
-
-
Africa
-
-
-
-
Other areas
-
-
-
-
-
-
Total consolidated
operations
-
-
-
Equity affiliates
Canada
-
-
-
-
-
Asia Pacific/Middle East
-
-
-
Other areas
-
-
-
-
-
-
Total equity affiliates
-
-
-
*Our total proportionate interest was less than one.
The table below represents the status of our wells
drilling at December 31, 2019, 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, 2019.
Wells at December 31, 2019
Productive
In Progress
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Consolidated operations
Alaska
1,656
-
-
Lower 48
10,070
4,547
4,329
1,704
United States
11,726
5,544
4,329
1,704
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
-
-
-
-
Total consolidated
operations
13,523
5,996
4,478
1,762
Equity affiliates
Asia Pacific/Middle East
-
-
4,307
1,051
Total equity affiliates
-
-
4,307
1,051
Acreage at December 31, 2019
Thousands of Acres
Developed
Undeveloped
Gross
Net
Gross
Net
Consolidated operations
Alaska
1,331
1,320
Lower 48
2,569
2,012
10,337
8,396
United States
3,220
2,479
11,668
9,716
Canada
3,270
1,798
Europe
2,102
Asia Pacific/Middle East
1,538
9,910
5,735
Africa
12,545
2,049
Other areas
-
-
1,400
Total consolidated
operations
5,752
3,434
40,895
20,650
Equity affiliates
Asia Pacific/Middle East
3,723
Total equity affiliates
3,723
Costs Incurred
Year Ended
Millions of Dollars
December 31
Lower
Total
Asia Pacific/
Other
Alaska
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Unproved property acquisition
$
-
-
-
Proved property acquisition
-
-
-
-
-
-
Exploration
1,103
Development
1,125
3,028
4,153
-
5,501
$
1,508
3,579
5,087
7,193
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
-
-
Development
-
-
-
-
-
-
-
$
-
-
-
-
-
-
-
Consolidated operations
Unproved property acquisition
$
-
-
-
-
Proved property acquisition
2,227
2,243
-
-
-
-
2,249
2,346
2,488
-
-
-
-
2,620
Exploration
(6)
Development
2,715
3,433
-
5,226
$
3,267
3,357
6,624
8,821
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
-
-
Development
-
-
-
-
-
-
-
$
-
-
-
-
-
-
-
Consolidated operations
Unproved property acquisition
$
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
Exploration
Development
1,559
2,295
-
3,579
$
2,260
3,088
4,813
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
-
Development
-
-
-
-
-
-
$
-
-
-
-
-
-
Capitalized Costs
At December 31
Millions of Dollars
Lower
Total
Asia Pacific/
Other
Alaska
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Proved property
$
20,957
37,491
58,448
6,673
14,113
14,566
-
94,724
Unproved property
1,429
1,055
2,484
1,149
4,634
22,386
38,546
60,932
7,822
14,200
15,067
1,047
99,358
Accumulated depreciation,
depletion and amortization
9,419
26,294
35,713
2,050
9,017
10,253
57,421
$
12,967
12,252
25,219
5,772
5,183
4,814
41,937
Equity affiliates
Proved property
$
-
-
-
-
-
9,996
-
-
9,996
Unproved property
-
-
-
-
-
2,223
-
-
2,223
-
-
-
-
-
12,219
-
-
12,219
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
6,390
-
-
6,390
$
-
-
-
-
-
5,829
-
-
5,829
Consolidated operations
Proved property
$
20,154
35,269
55,423
5,946
23,520
14,866
-
100,657
Unproved property
1,184
1,125
2,309
1,083
4,662
21,338
36,394
57,732
7,029
23,708
15,740
1,021
105,319
Accumulated depreciation,
depletion and amortization
9,055
23,999
33,054
1,692
16,591
9,974
61,662
$
12,283
12,395
24,678
5,337
7,117
5,766
43,657
Equity affiliates
Proved property
$
-
-
-
-
-
9,990
-
-
9,990
Unproved property
-
-
-
-
-
2,162
-
-
2,162
-
-
-
-
-
12,152
-
-
12,152
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
5,960
-
-
5,960
$
-
-
-
-
-
6,192
-
-
6,192
Standardized Measure of Discounted Future Net Cash Flows
Relating 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 prescribed
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
U.S.
Canada
Europe
Middle East
Africa
Total
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
4,143
2,179
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
13,933
Discounted future net cash flows
$
9,681
10,019
19,700
1,944
2,174
2,977
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
34,542
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Consolidated operations
Future cash inflows
$
82,072
56,922
138,994
6,039
26,989
16,368
16,434
204,824
Less:
Future production costs
42,755
21,363
64,118
4,099
8,567
5,705
1,336
83,825
Future development costs
10,053
12,136
22,189
7,608
1,995
32,905
Future income tax provisions
5,538
4,418
9,956
-
7,102
2,873
13,492
33,423
Future net cash flows
23,726
19,005
42,731
1,334
3,712
5,795
1,099
54,671
10 percent annual discount
10,349
6,461
16,810
1,132
19,237
Discounted future net cash flows
$
13,377
12,544
25,921
3,341
4,663
35,434
Equity affiliates
Future cash inflows
$
-
-
-
-
-
33,606
-
33,606
Less:
Future production costs
-
-
-
-
-
16,449
-
16,449
Future development costs
-
-
-
-
-
1,228
-
1,228
Future income tax provisions
-
-
-
-
-
3,147
-
3,147
Future net cash flows
-
-
-
-
-
12,782
-
12,782
10 percent annual discount
-
-
-
-
-
4,853
-
4,853
Discounted future net cash flows
$
-
-
-
-
-
7,929
-
7,929
Total
company
Discounted future net cash flows
$
13,377
12,544
25,921
3,341
12,592
43,363
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
U.S.
Canada
Europe
Middle East
Africa
Total
Consolidated operations
Future cash inflows
$
44,969
44,556
89,525
5,479
23,137
15,207
13,181
146,529
Less:
Future production costs
29,524
18,947
48,471
4,417
8,128
5,398
1,401
67,815
Future development costs
7,255
10,881
18,136
8,758
2,511
30,638
Future income tax provisions
2,375
2,428
-
3,333
2,459
10,356
18,576
Future net cash flows
8,137
12,353
20,490
2,918
4,839
29,500
10 percent annual discount
2,712
4,358
7,070
1,032
8,891
Discounted future net cash flows
$
5,425
7,995
13,420
2,629
3,807
20,609
Equity affiliates
Future cash inflows
$
-
-
-
-
-
23,222
-
23,222
Less:
Future production costs
-
-
-
-
-
12,984
-
12,984
Future development costs
-
-
-
-
-
1,444
-
1,444
Future income tax provisions
-
-
-
-
-
2,083
-
2,083
Future net cash flows
-
-
-
-
-
6,711
-
6,711
10 percent annual discount
-
-
-
-
-
2,316
-
2,316
Discounted future net cash flows
$
-
-
-
-
-
4,395
-
4,395
Total
company
Discounted future net cash flows
$
5,425
7,995
13,420
2,629
8,202
25,004
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
Consolidated Operations
Equity Affiliates
Total Company
Discounted future net cash flows
at the beginning of the year
$
35,434
20,609
8,151
7,929
4,395
3,937
43,363
25,004
12,088
Changes during the year
Revenues less production
costs for the year
(13,424)
(14,909)
(9,844)
(1,673)
(1,651)
(1,341)
(15,097)
(16,560)
(11,185)
Net change in prices and
production costs
(13,538)
25,391
19,310
(422)
4,559
2,750
(13,960)
29,950
22,060
Extensions, discoveries and
improved recovery, less
estimated future costs
2,985
4,574
1,445
(4)
3,245
4,956
1,441
Development costs for the year
5,333
5,197
3,653
5,572
5,468
4,079
Changes in estimated future
development costs
(1,141)
1,225
(21)
(64)
(1,127)
1,161
Purchases of reserves in place,
less estimated future costs
3,033
-
-
-
-
3,033
-
Sales of reserves in place,
less estimated future costs
(1,997)
(1,531)
(855)
-
-
(786)
(1,997)
(1,531)
(1,641)
Revisions of previous quantity
estimates
2,099
(365)
2,300
(648)
2,168
(303)
1,652
Accretion of discount
5,144
3,055
1,313
6,013
3,540
1,726
Net change in income taxes
4,767
(8,479)
(6,089)
(80)
(588)
(288)
4,687
(9,067)
(6,377)
Total changes
(8,062)
14,825
12,458
(759)
3,534
(8,821)
18,359
12,916
Discounted future net cash flows
at year end
$
27,372
35,434
20,609
7,170
7,929
4,395
34,542
43,363
25,004
●
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.
Selected Quarterly Financial Data
(Unaudited)
Millions of Dollars
Per Share of Common Stock
Sales and
Net Income
Net Income (Loss)
Other
Income (Loss)
Net
(Loss)
Attributable
Operating
Before
Income
Attributable to
to ConocoPhillips
Revenues
Income Taxes
(Loss)
ConocoPhillips
Basic
Diluted
First
$
9,150
2,687
1,846
1,833
1.61
1.60
Second
7,953
2,058
1,597
1,580
1.40
1.40
Third
7,756
3,493
3,071
3,056
2.76
2.74
Fourth
7,708
1,286
0.66
0.66
First
$
8,798
1,776
0.75
0.75
Second
8,504
2,619
1,654
1,640
1.40
1.39
Third
9,449
2,906
1,873
1,861
1.60
1.59
Fourth
9,666
2,672
1,878
1,868
1.62
1.61
For additional information on the commodity price environment, see the
Business Environment and Executive Overview section of Management's Discussion
and
Analysis of Financial Condition and Results of Operations.
Supplementary Information-Condensed Consolidating
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 condensed consolidating financial
information
presents the results of operations, financial position
and cash flows for:
●
ConocoPhillips, ConocoPhillips Company and
Burlington Resources LLC (in each case, reflecting
investments in subsidiaries utilizing the equity
method of accounting).
●
All other nonguarantor subsidiaries of ConocoPhillips.
●
The consolidating adjustments necessary to present
ConocoPhillips’ results on a consolidated
basis.
In 2017, ConocoPhillips Company received a $
9.8
billion return of capital and a $
1.4
billion loan repayment
from nonguarantor subsidiaries to settle certain
accumulated intercompany balances.
These transactions had
no impact on our consolidated financial statements.
In 2017, ConocoPhillips received a $
7.8
billion return of capital and a $
0.2
billion return of earnings from
ConocoPhillips Company to settle certain
accumulated intercompany balances.
These transactions had no
impact on our consolidated financial statements.
In 2018, ConocoPhillips Company received a $
4.8
billion return of earnings and a $
2.4
billion loan repayment
from nonguarantor subsidiaries to settle certain
accumulated intercompany balances.
These transactions had
no impact on our consolidated financial statements.
In 2018, ConocoPhillips received a $
3.5
billion return of capital and a $
1.0
billion return of earnings from
ConocoPhillips Company to settle certain
accumulated intercompany balances.
These transactions had no
impact on our consolidated financial statements.
In 2019, ConocoPhillips received a $
2.4
billion return of capital and a $
1.7
billion return of earnings from
ConocoPhillips Company to settle certain
accumulated intercompany balances.
This transaction had no impact
on our consolidated financial statements.
In 2019, ConocoPhillips Company received a $
4.5
billion return of earnings and a $
4.2
billion return of capital
from nonguarantor subsidiaries to settle certain
accumulated intercompany balances.
These transactions had
no impact on our consolidated financial statements.
In 2019, Burlington Resources LLC received
a $
3.2
billion return of earnings from nonguarantor
subsidiaries
to settle certain accumulated intercompany balances.
These transactions had no impact on our consolidated
financial statements.
This condensed consolidating financial information
should be read in conjunction with the accompanying
consolidated financial statements and notes.
Millions of Dollars
Year Ended December 31,
Income Statement
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Revenues and Other Income
Sales and other operating revenues
$
-
14,510
-
18,057
-
32,567
Equity in earnings of affiliates
7,419
5,281
1,610
(14,306)
Gain (loss) on dispositions
-
2,786
-
(820)
-
1,966
Other income
-
1,358
Intercompany revenues
-
5,542
(5,695)
-
Total Revenues and Other
Income
7,420
23,565
1,655
24,031
(20,001)
36,670
Costs and Expenses
Purchased commodities
-
12,838
-
4,038
(5,034)
11,842
Production and operating expenses
1,380
4,345
(405)
5,322
Selling, general and administrative expenses
-
(5)
Exploration expenses
-
-
-
Depreciation, depletion and amortization
-
-
5,494
-
6,090
Impairments
-
-
-
Taxes other than income taxes
-
-
-
Accretion on discounted liabilities
-
-
-
Interest and debt expense
(251)
Foreign currency transaction losses
-
-
-
Other expenses
-
-
-
Total Costs and Expenses
16,594
15,820
(5,695)
27,146
Income before income taxes
7,127
6,971
1,521
8,211
(14,306)
9,524
Income tax provision (benefit)
(62)
(448)
(46)
2,823
-
2,267
Net income
7,189
7,419
1,567
5,388
(14,306)
7,257
Less: net income attributable to noncontrolling interests
-
-
-
(68)
-
(68)
Net Income Attributable to ConocoPhillips
$
7,189
7,419
1,567
5,320
(14,306)
7,189
Comprehensive Income Attributable to ConocoPhillips
$
7,935
8,165
1,873
6,058
(16,096)
7,935
Income Statement
Year Ended December 31,
Revenues and Other Income
Sales and other operating revenues
$
-
16,113
-
20,304
-
36,417
Equity in earnings of affiliates
6,503
8,142
1,953
1,072
(16,596)
1,074
Gain on dispositions
-
-
-
1,063
Other income (loss)
-
(384)
-
-
Intercompany revenues
5,627
(5,867)
-
Total Revenues and Other
Income
6,538
24,272
1,996
28,384
(22,463)
38,727
Costs and Expenses
Purchased commodities
-
14,591
-
5,131
(5,428)
14,294
Production and operating expenses
-
1,023
4,245
(59)
5,213
Selling, general and administrative expenses
-
(5)
Exploration expenses
-
-
-
Depreciation, depletion and amortization
-
-
5,372
-
5,956
Impairments
-
(10)
-
-
Taxes other than income taxes
-
-
-
1,048
Accretion on discounted liabilities
-
-
-
Interest and debt expense
(375)
Foreign currency transaction (gains) losses
(12)
(167)
-
(17)
Other expenses
-
-
Total Costs and Expenses
17,757
16,343
(5,867)
28,754
Income before income taxes
6,189
6,515
1,824
12,041
(16,596)
9,973
Income tax provision (benefit)
(68)
(41)
3,765
-
3,668
Net income
6,257
6,503
1,865
8,276
(16,596)
6,305
Less: net income attributable to noncontrolling interests
-
-
-
(48)
-
(48)
Net Income Attributable to ConocoPhillips
$
6,257
6,503
1,865
8,228
(16,596)
6,257
Comprehensive Income Attributable to ConocoPhillips
$
5,654
5,900
1,364
7,961
(15,225)
5,654
See Notes to Consolidated Financial Statements.
Millions of Dollars
Year Ended December 31,
Income Statement
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Revenues and Other Income
Sales and other operating revenues
$
-
12,433
-
16,673
-
29,106
Equity in earnings (losses) of affiliates
(454)
2,047
(2,477)
Gain on dispositions
-
-
1,261
-
2,177
Other income
-
-
Intercompany revenues
3,369
(3,721)
-
Total Revenues and Other
Income
(404)
15,722
22,565
(6,198)
32,584
Costs and Expenses
Purchased commodities
-
11,145
-
4,580
(3,250)
12,475
Production and operating expenses
-
-
4,366
(17)
5,162
Selling, general and administrative expenses
-
(6)
Exploration expenses
-
-
-
Depreciation, depletion and amortization
-
-
5,990
-
6,845
Impairments
-
1,159
-
5,442
-
6,601
Taxes other than income taxes
-
-
Accretion on discounted liabilities
-
-
-
Interest and debt expense
(448)
1,098
Foreign currency transaction (gains) losses
(43)
(137)
-
Other expenses
-
(6)
-
Total Costs and Expenses
15,893
(84)
22,458
(3,721)
35,199
Income (Loss) before income taxes
(1,057)
(171)
(2,477)
(2,615)
Income tax provision (benefit)
(202)
(337)
(1,566)
-
(1,822)
Net income (loss)
(855)
(454)
1,320
1,673
(2,477)
(793)
Less: net income attributable to noncontrolling interests
-
-
-
(62)
-
(62)
Net Income (Loss) Attributable to ConocoPhillips
$
(855)
(454)
1,320
1,611
(2,477)
(855)
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
(180)
1,672
2,275
(4,168)
(180)
See Notes to Consolidated Financial Statements.
Millions of Dollars
At December 31, 2019
Balance Sheet
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Assets
Cash and cash equivalents
$
-
3,439
-
1,649
-
5,088
Short-term investments
-
2,670
-
-
3,028
Accounts and notes receivable
2,088
3,881
(2,575)
3,401
Investment in Cenovus Energy
-
2,111
-
-
-
2,111
Inventories
-
-
-
1,026
Prepaid expenses and other current assets
-
1,906
-
2,259
Total Current Assets
10,828
8,652
(2,575)
16,913
Investments, loans and long-term receivables*
34,076
44,969
11,662
15,612
(97,413)
8,906
Net properties, plants and equipment
-
3,552
-
38,717
-
42,269
Other assets
2,210
(805)
2,426
Total Assets
$
34,085
60,114
11,917
65,191
(100,793)
70,514
Liabilities and Stockholders’ Equity
Accounts payable
$
-
2,670
3,084
(2,575)
3,200
Short-term debt
(3)
-
Accrued income and other taxes
-
-
-
1,030
Employee benefit obligations
-
-
-
Other accruals
1,518
-
2,045
Total Current Liabilities
3,669
5,799
(2,575)
7,043
Long-term debt
3,794
6,670
2,129
2,197
-
14,790
Asset retirement obligations and accrued environmental costs
-
-
5,030
-
5,352
Deferred income taxes
-
-
-
5,438
(804)
4,634
Employee benefit obligations
-
1,329
-
-
1,781
Other liabilities and deferred credits*
1,787
7,514
9,271
(17,534)
1,864
Total Liabilities
5,662
19,504
3,024
28,187
(20,913)
35,464
Retained earnings
33,184
21,898
2,164
10,481
(27,985)
39,742
Other common stockholders’ equity
(4,761)
18,712
6,729
26,454
(51,895)
(4,761)
Noncontrolling interests
-
-
-
-
Total Liabilities and Stockholders’
Equity
$
34,085
60,114
11,917
65,191
(100,793)
70,514
Balance Sheet
At December 31, 2018
Assets
Cash and cash equivalents
$
-
1,428
-
4,487
-
5,915
Short-term investments
-
-
-
-
Accounts and notes receivable
5,646
6,707
(8,392)
4,067
Investment in Cenovus Energy
-
1,462
-
-
-
1,462
Inventories
-
-
-
1,007
Prepaid expenses and other current assets
-
-
Total Current Assets
8,987
12,572
(8,392)
13,274
Investments, loans and long-term receivables*
29,942
47,062
15,199
16,926
(99,465)
9,664
Net properties, plants and equipment
-
4,367
-
41,796
(465)
45,698
Other assets
1,269
(798)
1,344
Total Assets
$
29,975
61,058
15,504
72,563
(109,120)
69,980
Liabilities and Stockholders’ Equity
Accounts payable
$
-
5,098
7,113
(8,392)
3,895
Short-term debt
(3)
(9)
Accrued income and other taxes
-
-
1,235
-
1,320
Employee benefit obligations
-
-
-
Other accruals
-
1,259
Total Current Liabilities
6,420
9,170
(8,401)
7,395
Long-term debt
3,791
7,151
2,143
2,249
(478)
14,856
Asset retirement obligations and accrued environmental costs
-
-
7,273
-
7,688
Deferred income taxes
-
-
-
5,819
(798)
5,021
Employee benefit obligations
-
1,340
-
-
1,764
Other liabilities and deferred credits*
9,277
8,126
(17,775)
1,192
Total Liabilities
4,598
24,603
3,106
33,061
(27,452)
37,916
Retained earnings
27,512
18,511
1,113
9,764
(22,890)
34,010
Other common stockholders’ equity
(2,135)
17,944
11,285
29,613
(58,778)
(2,071)
Noncontrolling interests
-
-
-
-
Total Liabilities and Stockholders’
Equity
$
29,975
61,058
15,504
72,563
(109,120)
69,980
*Includes intercompany loans.
See Notes to Consolidated Financial Statements.
Millions of Dollars
Year Ended December 31,
Statement of Cash Flows
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
$
1,457
7,986
3,207
9,803
(11,349)
11,104
Cash Flows From Investing Activities
Capital expenditures and investments
-
(2,517)
-
(5,714)
1,595
(6,636)
Working capital changes associated
with investing activities
-
-
(140)
-
(103)
Proceeds from asset dispositions
2,374
7,047
1,055
(8,233)
3,012
Net purchases of investments
-
(2,803)
-
(107)
-
(2,910)
Long-term advances/loans-related parties
-
(812)
-
-
-
Collection of advances/loans-related parties
-
-
(161)
Intercompany cash management
1,060
(2,849)
1,402
-
-
Other
-
(149)
-
-
(108)
Net Cash Provided by (Used in) Investing Activities
3,434
(1,905)
2,171
(4,331)
(5,987)
(6,618)
Cash Flows From Financing Activities
Issuance of debt
-
-
-
(812)
-
Repayment of debt
-
(21)
-
(220)
(80)
Issuance of company common stock
-
-
-
(135)
(30)
Repurchase of company common stock
(3,500)
-
-
-
-
(3,500)
Dividends paid
(1,500)
(4,034)
(454)
(7,097)
11,585
(1,500)
Other
-
(4,924)
(1,736)
6,537
(119)
Net Cash Used in Financing Activities
(4,891)
(4,055)
(5,378)
(8,241)
17,336
(5,229)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
-
(11)
-
(35)
-
(46)
Net Change in Cash, Cash Equivalents and Restricted Cash
-
2,015
-
(2,804)
-
(789)
Cash, cash equivalents and restricted cash at beginning of period
-
1,428
-
4,723
-
6,151
Cash, Cash Equivalents and Restricted Cash at End of Period
$
-
3,443
-
1,919
-
5,362
Statement of Cash Flows
Year Ended December 31,
2018*
Cash Flows From Operating Activities
Net Cash
Provided by Operating Activities
$
4,019
14,132
(6,915)
12,934
Cash Flows From Investing Activities
Capital expenditures and investments
-
(980)
(603)
(5,777)
(6,750)
Working capital changes associated
with investing activities
-
(110)
-
-
(68)
Proceeds from asset dispositions
3,457
1,926
(5,672)
1,082
Net sales of short-term investments
-
-
-
1,620
-
1,620
Long-term advances/loans-related parties
-
(126)
(173)
(10)
-
Collection of advances/loans-related parties
3,432
(4,243)
Intercompany cash management
(803)
3,504
(2,150)
(551)
-
-
Other
-
-
-
Net Cash Provided by (Used in) Investing Activities
3,243
6,537
(788)
(3,839)
(8,996)
(3,843)
Cash Flows From Financing Activities
Issuance
of debt
-
-
(309)
-
Repayment of debt
-
(4,865)
(53)
(4,320)
4,243
(4,995)
Issuance of company common stock
-
-
-
(133)
Repurchase of company common stock
(2,999)
-
-
-
-
(2,999)
Dividends paid
(1,363)
(1,043)
-
(6,057)
7,100
(1,363)
Other
(3,468)
-
(1,670)
5,010
(123)
Net Cash Used in Financing Activities
(4,103)
(9,366)
(53)
(11,748)
15,911
(9,359)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
-
-
(121)
-
(117)
Net Change in Cash, Cash Equivalents and Restricted Cash
-
1,194
(3)
(1,576)
-
(385)
Cash, cash equivalents and restricted cash at beginning of period
-
6,299
-
6,536
Cash, Cash Equivalents and Restricted Cash at End of Period
$
-
1,428
-
4,723
-
6,151
*Revised to reclassify certain intercompany distributions from Operating Activities to 'Proceeds from asset dispositions' within Investing Activities based on the nature of the distributions.
There was no impact to Total Consolidated results.
Millions of Dollars
Year Ended December 31,
Statement of Cash Flows
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
$
1,183
2,971
5,904
(3,052)
7,077
Cash Flows From Investing Activities
Capital expenditures and investments
-
(1,663)
(4,351)
(3,795)
5,218
(4,591)
Working capital changes associated
with investing activities
-
-
(62)
-
Proceeds from asset dispositions
7,765
11,146
12,178
12,796
(30,025)
13,860
Net purchases of short-term investments
-
-
-
(1,790)
-
(1,790)
Long-term advances/loans-related parties
-
(214)
(65)
(20)
-
Collection of advances/loans-related parties
1,527
2,196
(4,655)
Intercompany cash management
1,151
(1,341)
-
-
Other
-
(8)
-
-
Net Cash Provided by Investing Activities
9,574
11,083
6,810
9,458
(29,163)
7,762
Cash Flows From Financing Activities
Issuance of debt
-
-
(299)
-
Repayment of debt
(5,459)
(4,411)
-
(2,661)
4,655
(7,876)
Issuance of company common stock
-
-
-
(178)
(63)
Repurchase of company common stock
(3,000)
-
-
-
-
(3,000)
Dividends paid
(1,305)
(235)
-
(2,995)
3,230
(1,305)
Other
(7,765)
(9,781)
(7,377)
24,807
(112)
Net Cash Used in Financing Activities
(9,645)
(12,391)
(9,781)
(12,754)
32,215
(12,356)
Effect of Exchange Rate Changes on Cash and Cash Equivalents
-
(2)
-
Net Change in Cash and Cash Equivalents
-
(124)
(2)
2,841
-
2,715
Cash and cash equivalents at beginning of period
-
3,247
-
3,610
Cash and Cash Equivalents at End of Period
$
-
6,088
-
6,325
See Notes to Consolidated Financial Statements.

Item 9. Changes in and Disagreements with Accountants
Item 9.
CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.

Item 9A. Controls and Procedures
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, 2019,
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, 2019.
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
and is incorporated herein by reference.
Report of Independent Registered Public Accounting
Firm
This report is included in Item 8 on page
and is incorporated herein by reference.

Item 9B. Other Information
Item 9B.
OTHER INFORMATION
None.
PART
III

Item 10. Directors, Executive Officers and Corporate Governance
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND
CORPORATE GOVERNANCE
Information regarding our executive officers appears in
Part I of this report on page 29.
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
2020 Annual Meeting of Stockholders, to be
filed pursuant to Regulation 14A on or before
April 30, 2020, and
is incorporated herein by reference.*

Item 11. Executive Compensation
Item 11.
EXECUTIVE COMPENSATION
Information required by Item 11 of Part III will be included
in our Proxy Statement relating to our 2020
Annual Meeting of Stockholders, to be filed pursuant
to Regulation 14A on or before April 30,
2020, and is
incorporated herein by reference.*

Item 12. Security Ownership of Certain Beneficial Owners and Management
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 2020
Annual Meeting of Stockholders, to be filed pursuant
to Regulation 14A on or before April 30,
2020, and is
incorporated herein by reference.*

Item 13. Certain Relationships and Related Transactions
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 2020
Annual Meeting of Stockholders, to be filed pursuant
to Regulation 14A on or before April 30,
2020, and is
incorporated herein by reference.*

Item 14. Principal Accountant Fees and Services
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 2020
Annual Meeting of Stockholders, to be filed pursuant
to Regulation 14A on or before April 30,
2020, 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 2020 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.
PART
IV

Item 15. Exhibits and Financial Statement Schedules
Item 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1.
Financial Statements and Supplementary
Data
The financial statements and supplementary information
listed in the Index to Financial Statements,
which appears on page
, are filed as part of this annual report.
2.
Financial Statement Schedules
Schedule II-Valuation and Qualifying Accounts, appears below.
All other 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.
3.
Exhibits
The exhibits listed in the Index to Exhibits, which
appears on pages
through 196, are filed as part
of this annual report.
SCHEDULE II-VALUATION
AND QUALIFYING ACCOUNTS (Consolidated)
ConocoPhillips
Millions of Dollars
Balance at
Charged to
Balance at
Description
January 1
Expense
Other
(a)
Deductions
December 31
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
-
(17)
(b)
Deferred tax asset valuation allowance
3,040
7,376
(26)
(176)
10,214
Included in other liabilities:
Restructuring accruals
(1)
-
(24)
(c)
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
-
(2)
(b)
Deferred tax asset valuation allowance
1,254
2,067
(8)
(273)
3,040
Included in other liabilities:
Restructuring accruals
(2)
(73)
(c)
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable
$
-
(3)
(b)
Deferred tax asset valuation allowance
-
1,254
Included in other liabilities:
Restructuring accruals
(93)
(c)
(a)Represents acquisitions/dispositions/revisions and the effect of translating foreign financial statements.
(b)Amounts charged off less recoveries of amounts previously charged off.
(c)Benefit payments.
See Note 19
-
Income Taxes, in the Notes to Consolidated Financial Statements, for additional information related to our deferred
tax asset valuation allowance.
CONOCOPHILLIPS
INDEX TO EXHIBITS
Exhibit
Number
Description
2.1
Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 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. (incorporated by reference to
Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed
by ConocoPhillips on May 4, 2017).
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. (incorporated by
reference to Exhibit 2.2 to the Current Report of ConocoPhillips on Form 8-K filed on May 18,
2017; File No. 001-32395).
3.1
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008;
File No. 001-32395).
3.2
Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips
(incorporated by reference to Exhibit 3.2 to the Current Report of ConocoPhillips on Form 8-K filed
on August 30, 2002; File No. 000-49987).
3.3
Amended and Restated By-Laws of ConocoPhillips, as amended and restated as of October 9, 2015
(incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed
on October 13, 2015; File No. 001-32395).
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.
10.1
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
10.2
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
Exhibit
Number
Description
10.3
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.4
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended
December 31, 1999; File No. 001-00720).
10.5
Amendment and Restatement of ConocoPhillips Supplemental Executive Retirement Plan, dated
April 19, 2012
(incorporated by reference to Exhibit 10.14 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.6
Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference
to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.7
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
10.8
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
10.9
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to
Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.10.1*
Amended and Restated ConocoPhillips Key Employee Supplemental Retirement Plan, dated
January 1, 2020.
10.10.2
Eighth Amendment to Retirement Plans as amended and restated effective January 1, 2016
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended June 30, 2018; File No. 001-32395).
10.11.1*
Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips-Title I, dated
January 1, 2020.
10.11.2*
Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips-Title II, dated
January 1, 2020.
10.12
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).
10.13
Amendment and Restatement of 1998 Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2002; File No. 000-49987).
10.14
Amendment and Restatement of 1998 Key Employee Stock Performance Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2002; File No. 000-49987).
Exhibit
Number
Description
10.15
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
10.16.1
Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of the
Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended
December 31, 1999; File No. 001-14521).
10.16.2
Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.16.3
Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998 (incorporated by
reference to Exhibit 10.17.3 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2015; File No. 001-32395).
10.16.4
First Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated May 3, 1999 (incorporated by reference to Exhibit 10.17.4 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.5
Second Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated January 15, 2002 (incorporated by reference to Exhibit 10.17.5 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
10.16.6
Third Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated October 5, 2006 (incorporated by reference to Exhibit 10.17.6 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
32395).
10.16.7
Fourth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 1, 2012 (incorporated by reference to Exhibit 10.17.7 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.8
Fifth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 20, 2015 (incorporated by reference to Exhibit 10.17.8 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.17.1
ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003;
File No. 000-49987).
10.17.2
First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program
(incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarterly period ended June 30, 2008; File No. 001-32395).
10.18
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2003; File No. 000-49987).
10.19.1*
Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips-Title I,
dated January 1, 2020 (incorporated by reference to Exhibit 10.12.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
Exhibit
Number
Description
10.19.2*
Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips-Title II,
dated January 1, 2020 (incorporated by reference to Exhibit 10.12.2 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.20
Amendment and Restatement of ConocoPhillips Key Employee Change in Control Severance Plan,
effective January 1, 2014 (incorporated by reference to Exhibit 10.21 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2013; File No. 001-32395).
10.21
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-
32395).
10.22.1
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual
Meeting of Shareholders; File No. 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
(incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2008; File No. 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 (incorporated by
reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2008; File No. 001-32395).
10.23
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7,
2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2007; File No. 001-32395).
10.24
2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2009 Annual
Meeting of Shareholders; File No. 001-32395).
10.25.1
2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2011 Annual
Meeting of Shareholders; File No. 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 (incorporated by reference to Exhibit 10 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2012; File No. 001-32395).
10.25.3
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated September 18, 2012
(incorporated by reference to Exhibit 10.26.5 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 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
(incorporated by reference to Exhibit 10.26.6 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
Exhibit
Number
Description
10.25.5
Form of Performance Share Unit Agreement-Canada under the Restricted Stock Program under
the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.7 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.6
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.8 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 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 (incorporated by reference to Exhibit 10.26.9 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2012; File No. 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 (incorporated by reference to Exhibit 10.1
to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2013;
File No. 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 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 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 (incorporated by reference to Exhibit 10.26.12 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.25.11
Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 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, 2014 (incorporated by reference to Exhibit 10.3 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-
32395).
10.25.13
Form of Performance Period IX Award Agreement-Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.4 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No.
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, 2014 (incorporated by reference to Exhibit 10.5 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
Exhibit
Number
Description
10.25.15
Form of Performance Period XIV Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.23 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
001-32395).
10.25.16
Form of Performance Period XIV Award Agreement-Canada, as part of the ConocoPhillips
Performance Share Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 16, 2016 (incorporated by reference to Exhibit 10.26.24 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No.
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 (incorporated by reference to Exhibit 10.11
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File
No. 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 (incorporated by reference
to Exhibit 10.26.24 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2017; File No. 001-32395).
10.25.19
Form of Performance Share Unit Award Terms and Conditions for Performance Period 18 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 13, 2018 (incorporated by reference to Exhibit 10.26.25 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No. 001-32395).
10.26.1
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K filed on May 14, 2014; File
No. 001-32395).
10.26.2
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 3, 2015 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
2015; File No. 001-32395).
10.26.3
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
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended March 31, 2015; File No. 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 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of ConocoPhillips on Form
10-Q for the quarter ended March 31, 2016; File No. 001-32395).
10.26.5
Form of Non-Employee Director Restricted Stock Units Terms and Conditions - Canadian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.4 to the Quarterly
Exhibit
Number
Description
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 001-
32395).
10.26.6
Form of Non-Employee Director Restricted Stock Units Terms and Conditions - Norwegian Non-
Employee Directors, as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016 (incorporated by reference to Exhibit 10.5 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016; File No. 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 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.8
Form of Performance Share Unit Award Terms and Conditions for Performance Period 17, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 14, 2017 (incorporated by reference
to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended
March 31, 2017; File No. 001-32395).
10.26.9
Form of Performance Share Unit Award Terms and Conditions for Performance Period 17 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 14, 2017 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.10
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 14, 2017 (incorporated by reference to Exhibit 10.4 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
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 (incorporated by reference to Exhibit 10.27.12 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No.
001-32395).
10.26.12
Form of Key Employee Award Terms and Conditions for eligible employees on the Canada payroll,
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
(incorporated by reference to Exhibit 10.27.13 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 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, 2018 (incorporated by reference to Exhibit 10.27.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No. 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
(incorporated by reference to Exhibit 10.27.15 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 001-32395).
Exhibit
Number
Description
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*
Amended and Restated 409A Annex to Nonqualified Deferred Compensation Arrangements of
ConocoPhillips, dated January 1, 2020 (incorporated by reference to Exhibit 10.8 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.28
Amendment, Change of Sponsorship, and Restatement of Certain Nonqualified Deferred
Compensation Plans of ConocoPhillips, dated April 19, 2012 (incorporated by reference to Exhibit
10.10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012;
File No. 001-32395).
10.29
Amendment and Restatement of the Burlington Resources Inc. Management Supplemental Benefits
Plan, dated April 19, 2012 (incorporated by reference to Exhibit 10.9 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.30
Amendment and Restatement of Deferred Compensation Trust Agreement for Non-Employee
Directors of Phillips Petroleum Company, dated June 23, 1995 (incorporated by reference to Exhibit
10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016;
File No. 001-32395).
10.31
Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
10.32
Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66,
dated April 26, 2012 (incorporated by reference to Exhibit 10.2 to the Current Report of
ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).
10.33
Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated
by reference to Exhibit 10.3 to the Current Report of ConocoPhillips on Form 8-K filed on May 1,
2012; File No. 001-32395).
10.34
Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 12, 2012
(incorporated by reference to Exhibit 10.4 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.35
Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012
(incorporated by reference to Exhibit 10.5 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.36
ConocoPhillips Clawback Policy dated October 3, 2012 (incorporated by reference to Exhibit 10.3
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012;
File No. 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
(incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K
filed on March 21, 2016; File No. 001-32395).
Exhibit
Number
Description
10.38
Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated December 28, 2018
(incorporated by reference to Exhibit 10.39 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2019; File No. 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 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
2019; File No. 001-32395).
21*
List of Subsidiaries of ConocoPhillips.
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.
SIGNATURES
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 18, 2020
/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 18, 2020, 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/ Don E. Wallette, Jr.
Executive Vice President and
Don E. Wallette, Jr.
Chief Financial Officer
(Principal financial officer)
/s/ Catherine A. Brooks
Vice President and Controller
Catherine A. Brooks
(Principal accounting officer)
/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/ William H. McRaven
Director
William H. McRaven
/s/ Sharmila Mulligan
Director
Sharmila Mulligan
/s/ Arjun N. Murti
Director
Arjun N. Murti
/s/ Robert A. Niblock
Director
Robert A. Niblock