CONOCOPHILLIPS (COP) FY 2021 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
Item 7.
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
Management’s Discussion and Analysis is the company’s
analysis of its financial performance and of significant
trends that may affect future performance.
It should be read in conjunction with the financial statements
and
notes, and supplemental oil and gas disclosures included
elsewhere in this report.
It contains forward-looking
statements including, without limitation,
statements relating to the company’s
plans, strategies, objectives,
expectations and intentions
that are made pursuant to the “safe harbor” provisions of the Private Securities
Litigation Reform Act of 1995.
The words “anticipate,”
“believe,” “budget,”
“continue,”
“could,”
“effort,”
“estimate,”
“expect,”
“forecast,”
“goal,”
“guidance,”
“intend,” “may,”
“objective,”
“outlook,”
“plan,” “potential,”
“predict,” “projection,”
“seek,” “should,”
“target,” “will,”
“would,” and similar expressions
identify forward-looking
statements.
The company does not undertake
to update, revise or correct any of the forward-looking information
unless required to do so under the federal securities laws.
Readers are cautioned that such forward-looking
statements should be read in conjunction
with the company’s disclosures under the heading:
“CAUTIONARY
STATEMENT
FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS
OF THE PRIVATE
SECURITIES LITIGATION
REFORM ACT OF 1995,”
beginning on page
69.
The terms “earnings” and “loss” as used in Management’s
Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
Business Environment and Executive Overview
ConocoPhillips is one of the world’s
leading E&P companies based on both production and reserves
with
operations and activities in 14 countries.
Our diverse, low cost of supply portfolio
includes resource-rich
unconventional plays
in North America; conventional assets in North
America, Europe and Asia; LNG
developments; oil sands assets in Canada; and an
inventory of global conventional
and unconventional exploration
prospects.
Headquartered in Houston, Texas,
at December 31, 2021, we employed approximately
9,900 people
worldwide and had total
assets of $91 billion.
Completed Acquisitions
On January 15, 2021, we completed our acquisition
of Concho Resources Inc. (Concho), an independent
oil and gas
exploration and production
company with operations across
New Mexico and West Texas
in an all-stock
transaction for $13.1 billion.
See Note 3
.
In December 2021, we completed our acquisition
of Shell Enterprises LLC’s (Shell) assets in the
Delaware Basin in
an all-cash transaction for $8.7 billion after
customary adjustments.
Assets acquired include approximately
225,000 net acres of producing properties
located entirely in Texas.
See Note 3
.
See Item 1A “Risk Factors” for
further discussion of the risks related to integration of the assets acquired.
Overview
After an unprecedented 2020, the energy
landscape improved throughout
2021 with prices reaching pre-pandemic
levels in the second half of the year;
however,
we expect prices will continue to be cyclical
and volatile.
Our view is
that a successful business strategy
in the E&P industry must be resilient in lower price
environments while also
retaining upside during periods of higher prices.
As such,
we are unhedged, remain highly disciplined
in our
investment decisions and continually
monitor market fundamentals,
including OPEC Plus updates regarding
supply
guidance and inventory levels.
Although global oil demand improved through
2021, the global economic recovery
remains uncertain and subject to various
risk factors, including actions taken
to stem the proliferation
of COVID-
19.
Management’s Discussion and Analysis
Table of Contents
35
ConocoPhillips
2021 10-K
As the macro energy environment
continues to evolve, we
are embracing what we believe
sector leadership
requires through what we call
our triple mandate.
We believe that ConocoPhillips
will play an essential role in
meeting energy transition pathway
demand delivering superior and consistent
returns on and of capital through
the price cycles,
and achieving our net zero ambition
on operational emissions,
while retaining the flexibility to
successfully adapt as the future unfolds.
Our triple mandate is supported by financial principles
and capital allocation priorities that
should allow us to
deliver superior returns through the cycles.
Our financial principles consist of maintaining
balance sheet strength,
providing peer-leading distributions,
making disciplined investments, and delivering
ESG excellence, all of which
are in service to delivering competitive financial returns.
Our 2021 acquisitions of Concho and the Shell Permian
assets further reinforce our differential
value proposition.
In 2021, we successfully delivered on our priorities.
Total
company production was
1,567 MBOED yielding cash
provided by operating activities
of $17 billion.
We invested
$5.3 billion into the business in the form of capital
expenditures and provided returns
of capital to shareholders of approximately
$6 billion through our ordinary
dividend and share repurchases.
For 2021, our ordinary dividend returned $2.4 billion
which included an increase
from 43 cents per share to 46 cents
per share,
effective in December.
Share repurchases resumed
in February and
amounted to $3.6 billion inclusive of our paced
monetization program related
to the Cenovus Energy (CVE)
common shares owned.
See Note 5
.
We also demonstrated
our commitment to preserving our top-tier balance
sheet with an announcement to reduce the company’s
gross debt by $5 billion over five years
through a
combination of natural and accelerated
maturities.
As part of our ongoing portfolio high-grading
and optimization efforts,
in December 2021, we announced two
transactions in our Asia Pacific segment enhancing
our diverse portfolio.
This included notifying Origin Energy of
our intent to exercise
our preemption right to purchase
an additional 10 percent shareholding interest
in APLNG
for $1.645 billion, before customary
adjustments,
and the sale of our interests in Indonesia for
approximately $1.4
billion before customary adjustments.
In addition to those transactions, in January 2022, we entered
into a
divestiture agreement to sell our
interest in noncore assets within
our Lower 48 segment for $440 million.
These
transactions are expected to
close in the first half of 2022.
For more information on APLNG,
see Note 4
and for
more information on pending dispositions,
see Note 3
.
We announced an increase in our
disposition target to $4 to $5 billion in proceeds
by year-end 2023, with
approximately $2 billion sourced
from the Permian Basin.
As of year-end 2021, we have generated
$0.3 billion in
disposition proceeds.
The proceeds from these transactions will be used
in accordance with the company’s
priorities, including returns of capital to
shareholders and reduction of gross
debt.
In December 2021, we announced the initiation of a three-tier
return of capital framework.
This framework is
structured to continue delivering
a compelling, growing ordinary dividend and through
-cycle share repurchases.
It
includes the addition of a VROC tier.
The VROC tier will provide a flexible tool for
meeting our commitment of
returning greater than 30 percent
of cash from operating activities
during periods where commodity prices are
meaningfully higher than our planning price range.
We have set our expected
2022 total return of capital
from all
three tiers at approximately
$8 billion.
For more information on our three-tier return of capital framework, see
Capital Resources and Liquidity
.
Management’s Discussion and Analysis
Table of Contents
ConocoPhillips
2021 10-K
36
In 2021, we reaffirmed and improved
upon our commitment to ESG leadership
and excellence and the specific
targets we set in October 2020
when we became the first U.S.-based
oil and gas company to adopt
a Paris-aligned
climate-risk strategy.
Our commitment includes:
●
Net-zero ambition for
operational (scope 1 and 2) emissions
by 2050 with active advocacy for a price on
carbon to address end-use (scope 3) emissions;
●
Targeting
a reduction in gross operated
and net equity operational GHG emissions intensity
by 40 to 50
percent from 2016 levels by 2030;
●
Zero routine flaring by 2030, with
an ambition to get there by 2025;
●
10 percent reduction target
for methane emissions intensity
by 2025 from a 2019 baseline, in addition to
the 65 percent reduction we have
made since 2015;
●
Adding continuous methane detection devices to
our operations, with an initial focus
on the larger Lower
48 facilities;
●
Dedicated low carbon technology
organization responsible
for identifying and prioritizing global emissions
reduction initiatives and opportunities associated
with the energy transition,
CCUS and hydrogen; and
●
ESG performance factoring into
executive and employee compensation
programs.
To support
this commitment, in December 2021, we announced that
approximately $0.2 billion of our 2022
company-wide capital expenditures
would be dedicated to energy transition
efforts
across the company’s
global
operations aimed at accelerating
the reduction of the company’s
scope 1 and 2 emissions and to pursue business
opportunities that address end-use emissions and
early-stage low-carbon
technology opportunities that leverage
the company’s adjacencies.
Operationally,
we remain focused on safely
executing the business.
Production increased 440 MBOED or 39
percent in 2021, compared to 2020.
Production excluding Libya
for 2021 was 1,527 MBOED.
After adjusting for
closed acquisitions and dispositions, impacts from 2020 curtailments,
2021 Winter Storm Uri and the conversion
of
Concho two-stream contracted
volumes to a three-stream basis,
production increased
by 28 MBOED or 2 percent.
This increase was primarily due to new production
from the Lower 48 and other development
programs across the
portfolio,
partially offset by normal field decline.
Production from Libya averaged
40 MBOED in 2021.
Management’s Discussion and Analysis
Table of Contents
37
ConocoPhillips
2021 10-K
Key Operating and Financial
Summary
Significant items during 2021 and recent
announcements included the following:
●
Announced an increase to expected 2022 return
of capital to shareholders
to a total of $8 billion, with the
incremental $1 billion to be distributed
through share repurchases and
VROC tiers;
●
Acquired and integrated
Concho, capturing over $1 billion
of synergies and savings ahead of schedule;
acquired Shell’s Permian
assets on December 1, 2021;
●
Exercised preemption right
to purchase an additional 10 percent
shareholding interest in APLNG,
expected to close in the first quarter
of 2022;
●
Generated $0.3 billion in disposition proceeds
from noncore sales and entered
into agreements
to sell an
additional $1.8 billion in assets, subject to customary
closing adjustments;
●
Delivered strong operational
performance across the company’s
asset base, resulting in full-year
production of 1,527 MBOED, excluding
Libya;
●
Achieved first production from
GMT2, Malikai Phase 2, SNP Phase 2; completed
Tor II project
and started
production from a third Montney
multi-well pad;
●
Net cash provided by operating
activities was $17 billion, exceeding capital
expenditures and investments
of $5.3 billion;
●
Distributed $6.0 billion to shareholders
through $2.4 billion in dividends and $3.6 billion of share
repurchases, representing
over 30 percent return of cash
provided by operating activities
to shareholders;
●
Ended the year with cash and cash equivalents
of $5.0 billion and short-term investments
of $0.4 billion,
totaling over $5.4 billion in ending cash
and cash equivalents and short-term investments
;
●
Initiated a paced monetization of the company’s
CVE investment, generating $1.1
billion in proceeds
through the sale of 117 million shares, with the funds applied to
share repurchases; 91 million CVE shares
remained outstanding at year
-end 2021; and
●
Advanced the company’s
net-zero ambition by
announcing an increase in scope 1 and 2 GHG emissions-
intensity reduction targets
to 40 to 50 percent from a 2016 baseline on
a net equity and gross operated
basis by 2030, from the previous target
of 35 to 45 percent on only a gross operated
basis.
Business Environment
Brent crude oil prices averaged
$71 per barrel in 2021, compared with $42 per barrel in
2020.
The energy industry
has periodically experienced this type of volatility
due to fluctuating supply-and-demand conditions
and such
volatility may persist
in the future.
Commodity prices are the most significant factor
impacting our profitability
and related reinvestment
of operating cash flows into
our business.
Our strategy is to create
value through price
cycles by delivering on the financial principles that
underpin our value proposition; balance sheet strength,
peer
leading distributions, disciplined investments
and ESG excellence, all of which support
strong financial returns.
●
Balance sheet strength.
A strong balance sheet is a strategic
asset that provides flexibility through
price
cycles.
We strive to maintain
our ‘A’
-rating, and we have committed
to reducing gross debt by $5 billion
over the next five years.
This will reduce interest expense
and provide resilience in periods of volatility.
We ended the year with over
$5 billion in cash, maintaining balance sheet strength
even after completing
the all-cash acquisition of Shell’s
Permian assets.
●
Peer leading distributions.
We believe in delivering value
to our shareholders via our three-tiered
return
of capital framework,
which consists of a growing, sustainable
dividend, share repurchases, and
beginning
in 2022, the addition of VROC.
In 2021, we paid dividends on our common stock of approximately
$2.4
billion and repurchased $3.6 billion of our common stock
partially sourced from our paced monetization
program related to the
CVE common shares owned.
Our combined dividends
and repurchases
represented over 30 percent
of our net cash provided by operating
activities.
Our first VROC of $0.20
cents per share was paid on January 14, 2022, to
shareholders of record as of January
3, 2022.
Our VROC
will be made at the Board of Director’s
discretion, subject to market conditions
and other factors.
See
Note 5
.
See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain
considerations.”
Management’s Discussion and Analysis
Table of Contents
ConocoPhillips
2021 10-K
38
●
Disciplined investments.
Our goal is to achieve strong
free cash flow by exercising capital
discipline,
controlling our costs, and safely
and reliably delivering production.
We expect to make capital
investments sufficient to
sustain production throughout
the price cycles.
Free cash flow provides funds
that are available to return
to shareholders,
strengthen the balance sheet or reinvest
back into the
business for future cash flow expansion
.
o
Exercise capital discipline.
We participate in a commodity
price-driven and capital-intensive
industry, with varying
lead times from when an investment
decision is made to when an asset is
operational and generates
cash flow.
As a result, we must invest
significant capital dollars to
develop newly discovered fields,
maintain existing fields, and construct
pipelines and LNG
facilities.
We allocate capital
across a geographically diverse,
low cost of supply resource base,
which combined with legacy assets results
in low overall production decline.
Cost of supply is the
WTI equivalent price that generates
a 10 percent after-tax return
on a point-forward and fully
burdened basis.
Fully burdened includes capital infrastructure,
foreign exchange,
cost of carbon,
price-related inflation and G&A.
In setting our capital plans, we exercise
a rigorous approach
that evaluates projects
using these cost of supply criteria, which we believe will
lead to value
maximization and cash flow expansion
using an optimized investment pace,
not production
growth for growth’s
sake.
Our cash allocation priorities call for
the investment of sufficient
capital to sustain production
and provide returns of capital
to shareholders.
o
Control our costs.
Controlling operating and overhead
costs, without compromising safety
or
environmental stewardship,
is a high priority.
Using various methodologies, we monitor these
costs monthly,
on an absolute-dollar basis and a per-unit basis
and report to management.
Managing operating and overhead costs
is critical to maintaining a competitive position
in our
industry, particularly
in a low commodity price environment.
The ability to control our operating
and overhead costs positively impacts
our ability to deliver strong cash
from operations.
o
Optimize our portfolio.
In 2021, we completed the acquisition of Concho and
Shell’s Permian
assets, significantly increasing our unconventional
portfolio with many additional years
of low
cost of supply inventory.
The addition of this highly complementary acreage in the Midland
and
Delaware basins created
a sizeable Permian presence to augment
our leading unconventional
positions in the Eagle Ford and Bakken
in the Lower 48.
In our Asia Pacific segment, we notified
Origin Energy of our intent to exercise
our preemption right to purchase
an additional 10 percent
shareholding interest in
APLNG and announced the sale of our interests in
Indonesia.
See Note 3
.
We continue to evaluate
our assets to determine whether they
compete for capital within
our
portfolio and optimize as necessary,
directing capital towards
the most competitive investments
and disposing of assets that don’t compete.
As such, in conjunction with our Shell Permian
acquisition announcement, we communicated
an increase in our planned disposition target
to $4
to $5 billion in proceeds by year-end
2023 as part of our ongoing portfolio high-grading
and
optimization efforts.
o
Add to our proved reserve base.
We primarily add to our proved
reserve base in three ways:
◾
Acquire interest in existing
or new fields.
◾
Apply new technologies and processes to
improve recovery from existing
fields.
◾
Successfully explore, develop and exploit
new and existing fields.
As required by current authoritative
guidelines, the estimated future date
when an asset will
reach the end of its economic life is based on
historical 12-month first-of-month
average prices
and current costs.
This date estimates when production
will end and affects the amount of
estimated reserves.
Therefore, as prices and
cost levels change from year to year,
the estimate
of proved reserves also changes.
Generally, our
proved reserves decrease as prices
decline and
increase as prices rise.
Management’s Discussion and Analysis
Table of Contents
39
ConocoPhillips
2021 10-K
Reserve replacement represents
the net change in proved reserves, net
of production, divided by
our current year production, as
shown in our supplemental reserve table disclosures.
Our
reserve replacement was 377 percent
in 2021, reflecting a net increase from purchases
and sales
as well as higher prices.
Our organic reserve replacement,
which excluded a net increase of
1,115 MMBOE from sales and purchases, was
189 percent in 2021.
In the three years ended December 31, 2021, our reserve
replacement was 155 percent.
Our
organic reserve replacement
during the three years ended December 31, 2021, which
excluded a
net increase of 1,022 MMBOE related
to sales and purchases, was 88 percent.
Access to additional resources may become
increasingly difficult as commodity prices can
make
projects uneconomic or unattractive.
In addition, prohibition of direct investment
in some
nations, national fiscal terms, political
instability,
competition from national oil companies,
and
lack of access to high-potential areas due to
environmental or other regulation
may negatively
impact our ability to increase our reserve base.
As such, the timing and level at which we add to
our reserve base may,
or may not, allow us to fully replace our
production over subsequent
years.
●
ESG Leadership.
Safety and environmental
stewardship, including the operati
onal integrity of our assets,
remain our highest priorities.
We are committed to
protecting the health and safety
of everyone who has
a role in our operations and the communities
in which we operate.
We strive to conduct
our business
with respect and care for the local
and global environment and systematically
manage risk to drive
sustainable business operations.
In September 2021, we reaffirmed and improved
upon our commitment
to ESG leadership and excellence
and the specific targets that we set in
October 2020 when we became
the first U.S. based oil and gas
company to adopt a Paris-aligned
climate-risk strategy.
Our
comprehensive energy transition
strategy is designed to sustainably
meet global energy demand while
delivering competitive returns on and
of capital through the energy transition.
Our strategy also
recognizes the importance of
reducing society’s end-use emissions
to meet global climate goals.
As an
E&P company,
active only in the upstream side of the business, we do not
produce end-use products
directly for consumers.
We believe that if everyone
addressed their scope 1 and 2 emissions, scope
3
would also be addressed.
This is why we have consistently
taken a prominent role
in advocating that
scope 3 emissions be addressed through a well-designed
economywide price on carbon. In addition, we
are making early-stage investments
in transition opportunities with the potential
to generate competitive
returns that will help address end-use emissions,
including CCUS and Hydrogen.
We are also engaging
with our supply chain on their emissions targets.
Other significant factors that
can affect our profitability
include:
●
Energy commodity prices.
Our earnings and operating cash flows generally
correlate with crude oil and
natural gas commodity prices.
Commodity price levels are subject to factors
external to the company and
over which we have no control,
including but not limited to global economic health, supply
disruptions or
fears thereof caused by civil unrest
or military conflicts, actions taken
by OPEC Plus and other producing
countries, environmental
laws, tax regulations,
governmental policies, global pandemics and
weather-
related disruptions.
The following graph depicts the average
benchmark prices for WTI crude oil, Brent
crude oil and U.S. Henry Hub natural gas
over the past three years:
Management’s Discussion and Analysis
Table of Contents
ConocoPhillips
2021 10-K
40
Brent crude oil prices averaged
$70.73 per barrel in 2021, an increase of 70 percent compared
with
$41.68 per barrel in 2020.
Similarly, WTI crude oil prices
increased 72 percent from $39.37
per barrel in
2020 to $67.92 per barrel in 2021.
Following COVID-19 economic shutdowns
in early 2020, global oil
demand increased steadily through
the year alongside the global economic recovery.
OPEC
Plus supply
restraint, capital
discipline by U.S. E&P’s and various
unplanned supply disruptions in producing countries
moderated supply growth,
reducing excess global inventories
and putting upward pressure
on global oil
prices.
Henry Hub natural gas prices increased
85 percent from an average
of $2.08 per MMBTU in 2020 to $3.85
per MMBTU in 2021.
Extreme weather events in many
parts of the world and several global LNG
liquefaction outages depleted
global natural gas inventories
in early 2021, generating strong
demand for
U.S. LNG exports and supporting robust
domestic demand.
Our realized bitumen price increased 368 percent
from an average of $8.02
per barrel in 2020 to $37.52
per barrel in 2021.
The increase was largely driven
by strength in WTI, reflective
of increasing global
demand and OPEC discipline.
The WCS differential to WTI at
Hardisty remained fairly flat as
record high
production offsets incremental
pipeline capacity.
We continue to optimize
bitumen price realizations
through improvements in alternate
blend capability which results in lower diluent
costs and access to the
U.S. Gulf Coast market through
rail and pipeline contracts.
Our worldwide annual average
realized price increased 70 percent
from $32.15
per BOE in 2020 to $54.63
per BOE in 2021 primarily due to higher realized oil,
natural gas and bitumen prices.
North America’s energy
supply landscape has been transformed
from one of resource scarcity
to one of
abundance.
In recent years, the use of hydraulic
fracturing and horizontal
drilling in unconventional
formations has led to increased
industry actual and forecasted
crude oil and natural gas production
in the
U.S.
Although providing significant short
-
and long-term growth opportunities for
our company,
the
increased abundance of crude oil and natural
gas due to development of unconventional
plays could also
have adverse financial implications
to us, including: an extended period of low commodity
prices;
production curtailments; and delay
of plans to develop areas such as unconventional
fields.
Should one
or more of these events occur,
our revenues would be reduced, and
additional asset impairments might
be possible.
Management’s Discussion and Analysis
Table of Contents
41
ConocoPhillips
2021 10-K
●
Impairments
.
We participate in a capital
-intensive industry.
At times, our PP&E and investments
become
impaired when, for example,
commodity prices decline significantly for long periods
of time, our reserve
estimates are revised downward,
a decision to dispose of an asset leads to a write-down
to its fair value,
or the current fair value of an investment
is less than its carrying amount and the loss in value is deemed
other than temporary.
As we optimize our assets in the future, it is reasonably
possible we may incur
future losses upon sale or impairment charges to
long-lived assets used in operations,
investments in
nonconsolidated entities accounted
for under the equity method, and unproved
properties.
For more
information on our impairments,
see
Note 6
and
Note 7
.
●
Effective tax rate
.
Our operations are in countries
with different tax rates
and fiscal structures.
Accordingly,
even in a stable commodity price and fiscal/regulatory
environment, our overall
effective tax
rate can vary significantly
between periods based on the “mix” of before-tax
earnings within our global
operations.
●
Fiscal and regulatory environment
.
Our operations can be affected
by changing economic, regulatory
and political
environments in the various countries
in which we operate, including civil unrest
or strained
relationships with governments
that may impact our operations or
investments.
These changing
environments could negatively
impact our results of operations, and further changes
to increase
government fiscal take
could have a negative
impact on future operations.
Our management carefully
considers the fiscal and regulatory
environment when evaluating
projects or determining the levels and
locations of our activity.
Outlook
Production and Capital
2022 operating plan capital budget
is $7.2 billion.
The plan includes funding for ongoing development
drilling
programs, major projects, exploration
and appraisal activities, base maintenance and
$0.2 billion for projects to
reduce the company’s
scope 1 and 2 emissions intensity and investme
nts in several early-stage
low-carbon
opportunities that address end-use emissions.
Production guidance is 1.8 MMBOED in 2022 including Libya
but excluding the impacts from the pending
Indonesia
disposition and acquisition of additional APLNG shareholding interest.
First quarter 2022 production
is expected to
be 1.75 MMBOED to 1.79 MMBOED.
Operating Segments
We manage our operations
through six operating segments,
which are primarily defined by geographic
region:
Alaska; Lower 48; Canada; Europe, Middle
East and North Africa; Asia Pacific; and
Other International.
Corporate and Other represents
income and costs not directly associated
with an operating segment, such as most
interest expense, premiums
incurred on the early retirement
of debt, corporate overhead,
certain technology
activities, as well as licensing revenues.
Our key performance indicators,
shown in the statistical tables provided
at the beginning of the operating segment
sections that follow,
reflect results from our operations,
including commodity prices and production.
Results of Operations
Table of Contents
ConocoPhillips
2021 10-K
42
Results of Operations
This section of the Form 10-K discusses year-to-year comparisons
between 2021 and 2020.
For discussion of year-
to-year comparisons between 2020 and 2019, see "Management's
Discussion and Analysis of Financial Condition
and Results of Operations" in Part II, Item
7 of our 2020 10-K.
Consolidated Results
A summary of the company’s net
income (loss) attributable to ConocoPhillips
by business segment follows:
Millions of Dollars
Years Ended
December 31
2021
2020
2019
Alaska
$
1,386
(719)
1,520
Lower 48
4,932
(1,122)
436
Canada
458
(326)
279
Europe, Middle East and North Africa
1,167
448
3,170
Asia Pacific
453
962
1,483
Other International
(107)
(64)
263
Corporate and Other
(210)
(1,880)
38
Net income (loss) attributable to
ConocoPhillips
$
8,079
(2,701)
7,189
Net Income (loss) attributable to
ConocoPhillips increased $10.8 billion in 2021.
2021 earnings were positively
impacted by:
●
Higher realized commodity prices.
●
Higher sales volumes primarily due to our Concho acquisition and
absence of production curtailments.
See Note 3
.
●
A gain of $1,040 million after-tax on our
Cenovus Energy (CVE) common shares in 2021, as
compared to a
$855 million after-tax loss on those shares
in 2020.
●
Lower exploration expenses
due to:
o
Absence of a 2020 impairment for $648 million after
-tax for the entire carrying value
of
capitalized undeveloped leasehold
costs related to our Alaska
North Slope Gas asset.
o
Lower dry hole expenses.
o
Absence of early cancellation of our 2020 winter exploration
program in Alaska.
o
Absence of unproved property
impairment and dry hole expenses in 2020 for the Kamunsu
East
Field in Malaysia, which is no longer in our development
plans.
●
Higher equity in earnings of affiliates, primarily due to
higher LNG sales prices.
●
Contingent payments related
to prior dispositions in our Canada and Lower 48 segments.
●
An after-tax gain of $194 million recognized
for a FID bonus associated with our Australia
-West divestiture
in 2020.
See Note 3
.
●
Lower impairments, primarily due to the absence
of impairments recognized in 2020 for
noncore assets in
our Lower 48 segment partially offset
by an impairment in our APLNG investment
included within our Asia
Pacific segment.
See Note 7
.
These increases in net income (loss) were partly
offset by:
●
Higher production and operating expenses
and taxes other than income taxes,
primarily due to higher
sales volumes.
●
Higher DD&A expenses caused by higher production
volumes, partially offset by lower rates
driven from
positive reserve revisions due to higher
commodity prices in 2021.
●
Absence of a $597 million after-tax gain
on our Australia-West
divestiture completed in May
2020.
●
Restructuring and transaction expenses
of $341 million after-tax associated
with the Concho and Shell
acquisitions in addition to mark-to-market
impacts on certain key employee
compensation programs.
Results of Operations
Table of Contents
43
ConocoPhillips
2021 10-K
●
Realized losses on hedges of $233 million after
-tax related to derivative
positions assumed through our
Concho acquisition.
These derivative positions were settled
entirely within the first quarter of 2021.
See
Note 12
.
Income Statement Analysis
Unless otherwise indicated, all results in Income Statement
Analysis are before-tax.
Sales and other operating revenues
increased 144 percent in 2021, mainly due to higher
realized commodity prices
and higher sales volumes.
Equity in earnings of affiliates increased
$400 million in 2021, primarily due to higher earnings driven
by higher
LNG and crude prices, partially offset by a higher
effective tax rate
related to equity method investments
in our
Europe, Middle East and North Africa segment
.
Gain on dispositions decreased $63 million in 2021, primarily due
to the absence of a $587 million gain related
to
our 2020 Australia-West
divestiture and a $179 million loss associated
with the sale of noncore assets in our Other
International segment.
The decreases were partially offset
by $200 million related to a FID bonus
associated with
our Australia-West
divestiture,
gains recognized for contingent
payments associated with previous
dispositions in
our Canada and Lower 48 segments and gains
on sales of certain noncore assets in our Lower 48 segment.
Other income (loss) increased $1.7 billion in 2021, primarily due
to a gain of $1,040 million on our CVE common
shares in 2021, as compared to a $855 million loss on
those shares in 2020.
See Note 5
.
Purchased commodities increased 125 percent
in 2021, primarily in line with higher gas and crude prices
and
volumes.
Production and operating expenses
increased $1,350 million in 2021, primarily in line with higher production
volumes.
Selling, general and administrative
expenses increased $289 million in 2021, primarily due to
transaction and
restructuring expenses associated
with our Concho acquisition and higher compensation and benefits
costs,
including mark-to-market impacts of certain
key employee compensation
programs.
Exploration expenses decreased
$1,113 million in 2021, primarily due to the absence of 2020 expenses
including
an $828 million impairment for the entire
carrying value of capitalized
undeveloped leasehold costs related
to our
Alaska North Slope Gas asset, the early cancellation of our
2020 winter exploration
program in Alaska, and
absence
of unproved property impairment and
dry hole expenses from 2020 for the Kamunsu
East Field in Malaysia.
2021
also saw lower dry hole expenses in Alaska.
Impairments decreased $139 million in 2021, primarily due
to the absence of impairments recognized
in 2020 for
noncore assets in our Lower 48 segment partially
offset by an impairment in our APLNG investment
included
within our Asia Pacific segment in 2021.
For additional information,
see Note 7
and
Note 13
.
Taxes
other than income taxes increased
$880 million in 2021, caused primarily by higher commodity prices and
higher Lower 48 sales volumes.
Foreign currency transaction
(gains) losses decreased $50 million in 2021 due to the
absence of derivative gains
and other remeasurements.
See
Note 17—Income Taxes
for information regardin
g
our income tax provision
and effective tax rate.
Results of Operations
Table of Contents
ConocoPhillips
2021 10-K
44
Summary Operating Statistics
2021
2020
2019
Average Net Production
Crude oil (MBD)
Consolidated Operations
816
555
692
Equity affiliates
13
13
13
Total
crude oil
829
568
705
Natural gas liquids (MBD)
Consolidated Operations
134
97
107
Equity affiliates
8
8
8
Total
natural gas liquids
142
105
115
Bitumen (MBD)
69
55
60
Natural gas (MMCFD)
Consolidated Operations
2,109
1,339
1,753
Equity affiliates
1,053
1,055
1,052
Total
natural gas
3,162
2,394
2,805
Total Production
(MBOED)
1,567
1,127
1,348
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated Operations
$
67.61
39.56
60.98
Equity affiliates
69.45
39.02
61.32
Total
crude oil
67.64
39.54
60.99
Natural gas liquids (per bbl)
Consolidated Operations
31.04
12.90
18.73
Equity affiliates
54.16
32.69
36.70
Total
natural gas liquids
32.45
14.61
20.09
Bitumen (per bbl)
37.52
8.02
31.72
Natural gas (per mcf)
Consolidated Operations
6.00
3.17
4.25
Equity affiliates
5.31
3.71
6.29
Total
natural gas
5.77
3.41
5.03
Millions of Dollars
Worldwide Exploration
Expenses
General and administrative;
geological and geophysical,
lease rental, and other
$
300
374
322
Leasehold impairment
10
868
221
Dry holes
34
215
200
Total
Exploration Expenses
$
344
1,457
743
Results of Operations
Table of Contents
45
ConocoPhillips
2021 10-K
We explore for,
produce, transport and market
crude oil, bitumen, natural gas,
LNG and NGLs on a worldwide
basis.
At December 31, 2021, our operations
were producing in the U.S., Norway,
Canada, Australia, Indonesia,
China, Malaysia, Qatar and Libya.
Total production,
including Libya, of 1,567 MBOED increased 440 MBOED or 39 percent
in 2021 compared with
2020, primarily due to:
●
Higher volumes in Lower 48 due to our Concho acquisition
.
●
New wells online in Lower 48, Canada, Norway,
Malaysia and Alaska.
●
Absence of production curtailments,
primarily in our North American assets.
●
Higher production in Libya due to the absence of a
forced shutdown of the Es Sider export
terminal and
other eastern export terminals.
●
Improved well performance in
Norway,
Canada, Alaska and China.
The increase in production during 2021 was partly
offset by:
●
Normal field decline.
●
Absence of production from Australia
-West due to our second quarter
2020 disposition.
Production excluding Libya
for 2021 was 1,527 MBOED.
After adjusting for closed acquisitions
and dispositions,
impacts from 2020 curtailments, 2021 Winter
Storm Uri and the conversion
of Concho two-stream contracted
volumes to a three-stream basis,
production increased by 28 MBOED or 2 percent.
This increase was primarily due
to new production from the Lower 48 and other
development programs across
the portfolio,
partially offset by
normal field decline. Production from Libya
averaged 40 MBOED in 2021.
Results of Operations
Table of Contents
ConocoPhillips
2021 10-K
46
Alaska
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($MM)
$
1,386
(719)
1,520
Average Net Production
Crude oil (MBD)
178
181
202
Natural gas liquids (MBD)
16
16
15
Natural gas (MMCFD)
16
10
7
Total Production
(MBOED)
197
198
218
Average Sales Prices
Crude oil ($ per bbl)
$
69.87
42.12
64.12
Natural gas ($ per mcf)
2.81
2.91
3.19
The Alaska segment primarily explores for,
produces, transports and markets
crude oil, NGLs and natural gas.
In
2021, Alaska contributed 19 percent
of our consolidated liquids production
and less than 1 percent of our
consolidated natural
gas production.
Net Income (Loss) Attributable to ConocoPhillips
Alaska reported earnings of $1,386 million in 2021, compared
with a loss of $719 million in 2020.
Earnings were
positively impacted by:
●
Higher realized crude oil prices.
●
Absence of 2020 exploration expenses
,
including a $648 million after-tax impairment
associated with the
carrying value of our Alaska North Slope Gas assets
and the early cancellation of our winter exploration
program.
See Note 6
.
●
Lower dry hole expenses.
Earnings were negatively
impacted by:
●
Higher taxes other than income taxes
primarily due to higher realized crude oil prices.
Production
Average production
decreased 1 MBOED in 2021 compared with 2020, primarily
due to:
●
Normal field decline.
The production decrease was partly
offset by:
●
Absence of curtailments.
●
Improved production at
our Western North Slope assets
as a result of net royalty interest
changes
associated with periodic redetermination.
●
Improved performance in the Greater
Prudhoe Area and Western
North Slope assets.
●
New wells online across the segment.
Results of Operations
Table of Contents
47
ConocoPhillips
2021 10-K
Lower 48
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($MM)
$
4,932
(1,122)
436
Average Net Production
Crude oil (MBD)
447
213
266
Natural gas liquids (MBD)*
110
74
81
Natural gas (MMCFD)*
1,340
585
622
Total Production
(MBOED)
780
385
451
Average Sales Prices
Crude oil ($ per bbl)**
$
66.12
35.17
55.30
Natural gas liquids ($ per bbl)
30.63
12.13
16.83
Natural gas ($ per mcf)**
4.38
1.65
2.12
*Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021.
**Average sales prices, including the impact of hedges settling per initial contract terms in the first quarter of 2021 assumed in our
Concho
acquisition were $65.19 per barrel for crude oil and $4.33 per mcf for natural gas for the
year ended December 31, 2021.
As of March 31, 2021,
we had settled all oil and gas hedging positions acquired from Concho.
See Note 12
.
The Lower 48 segment consists of operations
located in the contiguous U.S. and
the Gulf of Mexico.
During 2021,
the Lower 48 contributed 55 percent
of our consolidated liquids production
and 64 percent of our consolidated
natural gas production.
Net Income (Loss) Attributable to ConocoPhillips
Lower 48 reported earnings of $4,932 million in 2021, compared
with a loss of $1,122 million in 2020.
Earnings
were positively impacted by:
●
Higher realized crude oil, NGL and natural
gas prices.
●
Higher sales volumes due to our Concho acquisition and the absence
of production curtailments.
●
Lower impairments, primarily related
to developed properties in our noncore
assets which were written
down to fair value due to lower commodity
prices and development plan changes.
See
Note 7
and
Note
13
.
●
Higher gains on dispositions related to
selling our interests in certain noncore
assets.
See Note 3
.
Earnings were negatively
impacted by:
●
Higher DD&A expenses, production and operating
expenses and taxes other than
income taxes primarily
due to higher production volumes.
Partially offsetting the increase
in DD&A expenses were lower rates
from price-related reserve revisions.
●
Impacts resulting from our Concho acquisition,
including higher selling, general and administrative
expenses for transaction and restructuring
charges, as well as realized losses
on derivative settlements.
See
Note 3
and
Note 12
.
Production
Total
average production
increased 395 MBOED in 2021 compared with 2020, primarily
due to:
●
Higher volumes due to our Concho acquisition.
●
New wells online from our development programs
in Permian, Eagle Ford
and Bakken.
●
Absence of curtailments.
These production increases were partly
offset by:
●
Normal field decline.
Results of Operations
Table of Contents
ConocoPhillips
2021 10-K
48
Canada
2021*
2020*
2019**
Net Income (Loss) Attributable
to ConocoPhillips
($MM)
$
458
(326)
279
Average Net Production
Crude oil (MBD)
8
6
1
Natural gas liquids (MBD)
4
2
-
Bitumen (MBD)
69
55
60
Natural gas (MMCFD)
80
40
9
Total Production
(MBOED)
94
70
63
Average Sales Prices
Crude oil ($ per bbl)
$
56.38
23.57
40.87
Natural gas liquids ($ per bbl)
31.18
5.41
19.87
Bitumen ($ per bbl)
37.52
8.02
31.72
Natural gas ($ per mcf)
2.54
1.21
0.49
*Average sales prices include unutilized transportation costs.
**Average prices for sales of bitumen produced excludes additional value realized from the purchase and sale of third-party volumes for
optimization of our pipeline capacity between Canada and the U.S. Gulf Coast.
Our Canadian operations consist of the Surmont
oil sands development in Alberta and the liquids-rich Montney
unconventional play in
British Columbia.
In 2021, Canada contributed 8 percent of our
consolidated liquids
production and 4 percent of our consolidated
natural gas production.
Net Income (Loss) Attributable to ConocoPhillips
Canada operations reported
earnings of $458 million in 2021 compared with a loss of $326 million in 2020.
Earnings were positively impacted
by:
●
Higher realized bitumen prices and crude
oil prices.
●
After-tax gains
on disposition related to contingent
payments of $246 million in 2021 associated
with the
sale of certain assets to CVE in 2017.
●
Higher sales volumes in our Surmont and Montney
assets.
Earnings were negatively impacted
by:
●
Higher production and operating expenses
primarily due to increased Surmont and Montney
production.
Production
Total
average production
increased 24 MBOED in 2021 compared with 2020.
The production increase was
primarily due to:
●
Improved well performance in
Surmont.
●
New wells online in Montney.
●
Production from our Kelt acquisition
completed in the third quarter of 2020.
●
Absence of curtailments.
Results of Operations
Table of Contents
49
ConocoPhillips
2021 10-K
Europe, Middle East and North Africa
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($MM)
$
1,167
448
3,170
Consolidated Operations
Average Net Production
Crude oil (MBD)
118
86
138
Natural gas liquids (MBD)
4
4
7
Natural gas (MMCFD)
313
275
478
Total Production
(MBOED)
175
136
224
Average Sales Prices
Crude oil ($ per bbl)
$
68.97
43.30
64.94
Natural gas liquids ($ per bbl)
43.97
23.27
29.37
Natural gas ($ per mcf)
13.27
3.23
4.92
The Europe, Middle East and North Africa
segment consists of operations
principally located in the Norwegian
sector of the North Sea; the Norwegian Sea; Qatar; Libya;
and terminalling operations in the U.K.
In 2021, our
Europe, Middle East and North Africa
operations contributed
12 percent of our consolidated liquids
production
and 14 percent of our consolidated
natural gas production.
Net Income Attributable to ConocoPhillips
The Europe, Middle East and North Africa
segment reported earnings of $1,167 million in 2021 compared
with
earnings of $448 million in 2020.
Earnings were positively impacted
by:
●
Higher realized natural
gas, crude oil and NGL prices.
●
Higher LNG sales prices, reflected in equity in earnings
of affiliates.
●
Higher sales volumes of crude oil and LNG.
Earnings were negatively
impacted by:
●
Higher taxes.
●
Higher DD&A expenses and production and
operating expenses.
Partly offsetting the increase
in DD&A
expenses were lower rates
from positive reserve revisions.
Consolidated Production
Average consolidated
production increased 39 MBOED in 2021, compared
with 2020.
The consolidated production
increase was primarily due to:
●
Higher production in Libya due to the absence
of a forced shutdown of the Es Sider export
terminal and
other eastern export terminals.
●
Improved well performance in
Norway.
●
New production from Norway
drilling activities, including our Tor
II redevelopment project which
achieved full production in 2021.
These production increases were partly
offset by:
●
Normal field decline.
Results of Operations
Table of Contents
ConocoPhillips
2021 10-K
50
Asia Pacific
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($MM)
$
453
962
1,483
Consolidated Operations
Average Net Production
Crude oil (MBD)
65
69
85
Natural gas liquids (MBD)
-
1
4
Natural gas (MMCFD)
360
429
637
Total Production
(MBOED)
125
141
196
Average Sales Prices
Crude oil ($ per bbl)
$
70.36
42.84
65.02
Natural gas liquids ($ per bbl)
-
33.21
37.85
Natural gas ($ per mcf)
6.56
5.39
5.91
The Asia Pacific segment has operations
in China, Indonesia, Malaysia and Australia.
During 2021, Asia Pacific
contributed 6 percent of our consolidated
liquids production and 17 percent of our consolidated
natural gas
production.
Net Income Attributable to ConocoPhillips
Asia Pacific reported earnings of $453 million
in 2021, compared with $962 million in 2020.
The decrease in earnings
was mainly due to:
●
An impairment of $688 million after-tax on
our APLNG investment.
See
Note 4
and
Note 13
.
●
Absence of a $597 million after-tax gain
related to our Australia
-West divestiture.
See Note 3
.
●
Absence of sales volumes associated with Australia
-West.
Earnings were positively impacted
by:
●
Higher crude oil and natural gas
prices.
●
Higher LNG sales prices, reflected in equity in earnings
of affiliates.
●
An after-tax gain of $194 million
recognized for a FID bonus associated
with our Australia-West
divestiture.
For additional information related
to this FID bonus, see
Note 3
and
Note 11
.
Consolidated Production
Average consolidated
production decreased 16 MBOED in 2021, compared
with 2020.
The decrease was primarily
due to:
●
The divestiture of our Australia
-West assets that contributed
18 MBOED in 2020.
●
Normal field decline.
These production decreases were partly
offset by:
●
Development activity at Bohai Bay
in China.
●
First production in Malikai
Phase 2 and SNP Phase 2.
●
The absence of curtailments across the segment
and increased demand in Indonesia from coal supply
restrictions.
Results of Operations
Table of Contents
51
ConocoPhillips
2021 10-K
Other International
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($MM)
$
(107)
(64)
263
The Other International segment includes exploration
and appraisal activities in Colombia as well as contingencies
associated with prior operations
in other countries.
As a result of our Concho acquisition, we refocused
our
exploration program
and announced our intent to pursue
managed exits
from certain areas.
Other International operations
reported a loss of $107 million in 2021, compared with a
loss of $64 million in 2020.
Earnings were negatively
impacted by:
●
A $137 million after-tax loss on divestiture
related to our Argentina
exploration interests.
See Note 3
.
●
Absence of a $29 million after-tax benefit to earnings
from the dismissal of arbitration
related to prior
operations in Senegal recognized
in the first quarter of 2020.
Changes to earnings were positively impacted
by:
●
Absence of exploration expenses
associated with dry hole costs and a full impairment of
capitalized
undeveloped leasehold costs in Colombia in the fourth
quarter of 2020.
Corporate and Other
Millions of Dollars
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
Net interest
$
(801)
(662)
(604)
Corporate general and administrative
expenses
(317)
(200)
(252)
Technology
25
(26)
123
Other
883
(992)
771
$
(210)
(1,880)
38
Net interest consists
of interest and financing expense,
net of interest income and capitalized
interest.
Net
interest expense increased $139
million in 2021 compared with 2020, primarily due to higher
debt balances
assumed due to our Concho acquisition.
See Note 9
.
Corporate G&A expenses include
compensation programs and
staff costs.
These expenses increased by $117
million in 2021 compared with 2020, primarily due to restructuring
expenses associated with our Concho
acquisition and mark to market adjustments
associated with certain compensation programs
.
See Note 16
.
Technology includes
our investment in new technologies
or businesses, as well as licensing revenues.
Activities are
focused on both conventional
and tight oil reservoirs, shale gas,
heavy oil, oil sands, enhanced oil recovery as well
as LNG.
Earnings from Technology
increased by $51 million in 2021 compared with 2020,
primarily due to higher
licensing revenues.
The category “Other” includes certain foreign currency
transaction gains and losses,
environmental costs
associated with sites no longer in operation,
other costs not directly associated with an
operating segment,
premiums incurred on the early retirement
of debt,
holding gains or losses on equity securities, and
pension
settlement expense.
Earnings in “Other” increased by $1,875 million in 2021 compared
with 2020, primarily due
to a gain of $1,040 million on our CVE common shares
in 2021, compared with a $855 million loss in 2020.
Capital Resources and Liquidity
Table of Contents
ConocoPhillips
2021 10-K
52
Capital Resources and Liquidity
Financial Indicators
Millions of Dollars
Except as Indicated
2021
2020
2019
Net cash provided by operating
activities
$
16,996
4,802
11,104
Cash and cash equivalents
5,028
2,991
5,088
Short-term investments
446
3,609
3,028
Short-term debt
1,200
619
105
Total
debt
19,934
15,369
14,895
Total
equity
45,406
29,849
35,050
Percent of total debt to
capital*
31
%
34
30
Percent of floating-rate
debt to total debt
4
%
7
5
*Capital includes total debt and total equity.
To meet our
short-
and long-term liquidity requirements,
we look to a variety of funding sources,
including cash
generated from operating
activities, proceeds from asset sales,
our commercial paper and credit facility programs
and our ability to sell securities using our shelf registration
statement.
In 2021, the primary uses of our available
cash were $8.7 billion for the acquisition
of Shell Permian;
$5.3 billion to support our ongoing capital expenditures
and investments program;
$3.6 billion to repurchase our common stock;
$2.4 billion to pay dividends;
and $1.2
billion for hedging, transaction and restructuring
costs.
In 2021, cash and cash equivalents increased by
$2.0
billion to $5.0 billion.
At December 31, 2021, we had cash and cash
equivalents of $5.0 billion, short-term investments
of $0.4 billion,
and available borrowing capacity
under our credit facility of $6.0 billion, totaling
approximately $11.5 billion
of
liquidity.
We believe current cash
balances and cash generated by
operations, together with access to
external
sources of funds as described below in the “Significant Changes
in Capital” section, will be sufficient to meet our
funding requirements in the near- and
long-term, including our capital spending program,
dividend payments and
required debt payments.
Significant Changes in Capital
Operating Activities
In 2021, cash provided by operating
activities was $17 billion, compared with $4.8 billion
for 2020.
The increase is
primarily due to higher realized commodity
prices and higher sales volumes,
mostly resulting from our acquisition
of Concho.
The increase was partly offset by
the $0.8 billion in settlement of oil and gas hedging
positions
acquired from Concho, and approximately
$0.4 billion of transaction and restructuring
costs.
Our short-
and long-term operating cash flows
are highly dependent upon prices for crude oil, bitumen,
natural
gas, LNG and NGLs.
Prices and margins in our industry have historically
been volatile and are driven by market
conditions over which we have no
control.
Absent other mitigating factors,
as these prices and margins fluctuate,
we would expect a corresponding change
in our operating cash flows.
The level of absolute production volumes,
as well as product and location mix, impacts our cash
flows.
Full-year
production averaged
1,567 MBOED in 2021.
Full-year production excluding
Libya averaged 1,527
MBOED.
Adjusting for closed acquisitions and dispositions,
impacts from 2020 curtailments, 2021 Winter Storm
Uri and the
conversion of Concho two-stream
contracted volumes to a
three-stream basis, production
increased 28 MBOED or
2 percent.
First quarter 2022 production
is expected to be 1.75 MMBOED to 1.79 MMBOED.
Future production is
subject to numerous uncertainties, including,
among others, the volatile crude oil and natural
gas price
environment, which may impact
investment decisions; the effects
of price changes on production sharing and
variable-royalty contracts;
acquisition and disposition of fields; field production decline rates;
new technologies;
operating efficiencies; timing of startups
and major turnarounds; political instability;
weather-related disruptions;
Capital Resources and Liquidity
Table of Contents
53
ConocoPhillips
2021 10-K
and the addition of proved reserves through
exploratory success and their timely and cost
-effective
development.
While we actively manage these factors,
production levels can cause variability
in cash flows,
although generally this variability has
not been as significant as that caused by commodity prices.
To maintain
or grow our production volumes on
an ongoing basis, we must continue to add
to our proved reserve
base.
Our proved reserves generally
increase as prices rise and decrease as prices decline.
Reserve replacement
represents the net change in proved
reserves, net of production, divided by our current
year production.
For
information on proved
reserves, including both developed and undeveloped
reserves,
see the reserve table
disclosures contained in “Supplementary Data – Oil and Gas Operations.”
See “Item 1A—Risk Factors – Unless we
successfully develop our resources, the scope of our business will decline, resulting in an adverse impact to our
business.”
As discussed in the “Critical Accounting Estimates”
section, engineering estimates of proved
reserves are
imprecise; therefore, reserves
may be revised upward or
downward each year due to the impact of changes
in
commodity prices or as more technical data
becomes available on reservoirs.
It is not possible to reliably predict
how revisions will impact future reserve quantities.
Investing Activities
In 2021, we invested $5.3 billion
in capital expenditures.
Capital expenditures invested
in 2020 and 2019 were
$4.7 billion and $6.6 billion, respectively.
For information about our
capital expenditures and investments,
see the
“Capital Expenditures and Investments”
section.
In December 2021, we completed our acquisition
of Shell’s assets in
the Delaware Basin for cash consideration
of
approximately $8.7 billion after
customary adjustments.
We funded this transaction with cash
on hand.
We
completed our acquisition of Concho on January 15, 2021.
The assets acquired in the transaction included
$382
million of cash.
The net impact of these items is recognized
within “Acquisition
of businesses, net of cash
acquired” on our consolidated sta
tement of cash flows.
See Note 3.
In 2021, we announced a disposition target
of $4 to $5 billion in disposition proceeds by year-end
2023.
Only
proceeds from transactions announced
or initiated in the third quarter of 2021 or later
will be counted toward this
target.
The proceeds from these transactions
will be used in accordance with the company’s
priorities, including
returns of capital to shareholders
and reduction of gross debt.
To date,
we have achieved $0.3 billion from
the
sale of noncore assets in our Lower 48 segment.
Total
proceeds from asset dispositions
in 2021 were $1.7 billion.
Including the $250 million mentioned above, we
also received cash proceeds of $1.14 billion from
sales of our investment in CVE
common shares and $244 million
of contingent payments related
to dispositions completed before
2021.
See Note 3.
In May 2021, we announced
and began a paced monetization of our
investment in CVE with the plan to
direct proceeds toward
our existing
share repurchase program.
We expect to fully dispose
of our CVE common shares by early 2022, however,
the
sales pace will be guided by market conditions,
and we retain discretion to
adjust accordingly.
See Note 5.
Proceeds from asset sales in 2020 were $1.3
billion.
We received cash
proceeds of $765 million for the divestiture
of our Australia-West
assets and operations.
We also received proceeds of $359
million and $184 million from the
sale of our Niobrara interests
and Waddell Ranch interests
in the Lower 48, respectively.
Proceeds from asset sales in 2019 were $3.0
billion, including $2.2 billion for the sale of two ConocoPhillips
U.K.
subsidiaries and $350 million for the sale of our 30 percent
interest in the Greater
Sunrise Fields.
See Note 3.
We invest in short
-term investments as part of our
cash investment strategy,
the primary objective of which is to
protect principal, maintain liquidity
and provide yield and total returns;
these investments include time deposits,
commercial paper,
as well as debt securities classified as available
for sale.
Funds for short-term needs
to support
our operating plan and provide resiliency
to react to short-term price volatility
are invested in highly liquid
instruments with maturities within the year.
Funds we consider available to maintain
resiliency in longer term
Capital Resources and Liquidity
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ConocoPhillips
2021 10-K
54
price downturns and to capture opportunities
outside a given operating plan may
be invested in instruments
with
maturities greater than one year.
See Note 12
.
Financing Activities
We have a revolving
credit facility totaling $6.0 billion, expiring
in May 2023.
Our revolving credit facility
may be
used for direct bank borrowings,
the issuance of letters of credit totaling
up to $500 million, or as support for our
commercial paper program.
The revolving credit facility is broadly
syndicated among financial institutions
and
does not contain any material
adverse change provisions or any
covenants requiring maintenance of specified
financial ratios or credit ratings.
The facility agreement contains
a cross-default provision relating
to the failure to
pay principal or interest
on other debt obligations of $200 million or more by
ConocoPhillips, or any of its
consolidated subsidiaries.
The amount of the facility is not subject to the redetermination
prior to its expiration
date.
Credit facility borrowings may
bear interest at a margin above
rates offered
by certain designated banks in the
London interbank market or
at a margin above the overnight federal
funds rate or prime rates
offered by certain
designated banks in the U.S.
The agreement calls for commitment
fees on available, but unused,
amounts.
The
agreement also contains early termination
rights if our current directors
or their approved successors
cease to be a
majority of the Board of Directors.
The revolving credit facility supports
ConocoPhillips Company’s ability to
issue up to $6.0 billion of commercial
paper, which
is primarily a funding source for short-term working
capital needs.
Commercial paper maturities are
generally limited to 90 days.
With no commercial paper outstanding
and no direct borrowings or letters
of credit,
we had access to $6.0 billion in available borrowing
capacity under the revolving credit facility
at December 31,
2021.
On January 15, 2021, we completed the acquisition of Concho
in an all-stock transaction. In the acquisition,
we
assumed Concho’s publicly
traded debt and in December 2020, we launched an offer
to exchange Concho’s
publicly traded debt for debt issued
by ConocoPhillips.
There were no impacts to ConocoPhillips’
credit ratings as a
result of the debt exchange.
In June 2021, we reaffirmed our
commitment to preserving our ‘A’
-rated balance
sheet by restating our intent
to reduce gross debt by $5 billion over
the next five years, driving a more resilient
and
efficient capital structure.
See
Note 9
and
Note 3
.
On January 25, 2021, S&P revised the industry risk assessment
for the E&P industry to ‘Moderately
High’ from
‘Intermediate’ based on a view of increasing
risks from the energy transition,
price volatility,
and weaker
profitability.
On February 11, 2021, S&P downgraded its rating
of our long-term debt from “A”
to “A
-” with a
“stable” outlook and affirmed
this rating in November 2021.
In October 2021, Moody’s affirmed its “A3”
rating of
our long-term debt and revised its outlook
from “stable” to “positive”.
In December 2021, Fitch affirmed its rating
of our long-term debt as “A”
with a “stable” outlook.
We do not have any
ratings triggers on any of our corporate
debt that would cause an automatic default,
and
thereby impact our access to liquidity,
upon downgrade of our credit ratings.
If our credit ratings are downgraded
from their current levels, it could
increase the cost of corporate
debt available to us and restrict
our access to the
commercial paper markets.
If our credit rating were to deteriorate
to a level prohibiting us from accessing
the
commercial paper market, we
would still be able to access funds under our revolving
credit facility.
Certain of our project-related
contracts, commercial contracts
and derivative instruments contain
provisions
requiring us to post collateral.
Many of these contracts and instruments
permit us to post either cash or letters
of
credit as collateral.
At December 31, 2021 and 2020, we had direct
bank letters of credit of $337 million and
$249
million, respectively,
which secured performance obligations
related to various purchase
commitments incident to
the ordinary conduct of business.
In the event of credit ratings downgrades,
we may be required to post
additional
letters of credit.
We have a universal
shelf registration statement
on file with the SEC under which we have the
ability to issue and
sell an indeterminate amount of various
types of debt and equity securities.
Capital Resources and Liquidity
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55
ConocoPhillips
2021 10-K
Capital Requirements
For information about our capital
expenditures and investments,
see the “Capital Expenditures and Investments”
section.
Our debt balance at December 31, 2021, was $19.9 billion,
an increase of $4.6 billion from the balance at
December 31, 2020, driven by debt acquired as part
of the Concho acquisition.
Maturities of debt (including
payments for finance leases) due in
2022 of $1.1 billion will be paid from current cash
balances and cash generated
by operations.
See Note 9
.
In December 2021, we announced our expected 2022 return
of capital program and the initiation
of a three-tier
return of capital framework.
The framework is structured
to deliver a compelling, growing ordinary dividend
and
through-cycle share repurchases.
It includes the addition of a discretionary VROC tier.
The VROC will provide a
flexible tool for meeting our commitment
of returning greater than
30 percent of cash from operating
activities
during periods where commodity prices are meaningfully
higher than our planning price range.
We have set our
expected 2022 total capital returns
at approximately $8 billion,
consisting of distributions from each of the three
tiers.
Consistent with our commitment to
deliver value to shareholders,
in 2021, we paid $2.4 billion, $1.75 per share of
common stock, in ordinary dividends. This
was an increase over 2020 and 2019, when we paid $1.69 and
$1.34 per
share of common stock, respectively.
On February 3, 2022, we announced a quarterly dividend of $0.46 per share,
payable March 1, 2022, to stockholders
of record at the close of business on February
14, 2022.
On January 14,
2022, we paid the first VROC payment
of $0.20 per share to shareholders
of record as of January 3, 2022.
On
February 3, 2022, we announced a VROC of $0.30 per share,
payable on April 14, 2022, to stockholders
of record at
the close of business on March 31, 2022.
The ordinary dividend and VROC are subject to
numerous considerations
and will be determined and approved
each quarter by the Board of Directors.
We expect to announce the VROC
when we announce our ordinary
dividend, but the quarterly payouts
will be staggered from the ordinary dividend,
resulting in up to eight cash
distributions throughout the year.
In late 2016, we initiated our current
share repurchase program
with Board of Director’s authorization
of $25
billion of our common stock.
Share repurchases were $3.6
billion, $0.9 billion, and $3.5 billion in 2021, 2020, and
2019, respectively.
As of December 31, 2021, share repurchases
since the inception of our current program
totaled 247 million shares and $14 billion.
Repurchases are made at management’s
discretion, at prevailing prices,
subject to market conditions and
other factors.
For more information on factors
considered when determining the levels of returns
of capital
see “Item 1A—Risk
Factors – Our ability to execute our capital return program is subject to certain considerations.”
In addition to the priorities described above, we have
contractual obligations
to purchase goods and services of
approximately $11.8 billion.
We expect to fulfill $6 billion of these
obligations in 2022. These figures exclude
purchase commitments for jointly
owned fields and facilities where we are not
the operator.
Purchase obligations
of $5.3 billion are related to agreements
to access and utilize the capacity of third
-party equipment and facilities,
including pipelines and LNG product terminals, to
transport, process, treat and store
commodities.
Purchase
obligations of $5.3 billion are related
to market-based contracts
for commodity product purchases
with third
parties.
The remainder is primarily our net share of purchase
commitments for materials
and services for jointly
owned fields and facilities where we are the operator.
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ConocoPhillips
2021 10-K
56
Capital Expenditures and Investments
Millions of Dollars
2021
2020
2019
Alaska
$
982
1,038
1,513
Lower 48
3,129
1,881
3,394
Canada
203
651
368
Europe, Middle East and North Africa
534
600
708
Asia Pacific
390
384
584
Other International
33
121
8
Corporate and Other
53
40
61
Capital Program*
$
5,324
4,715
6,636
* Excludes capital related to acquisitions of businesses, net of capital acquired.
Our capital expenditures and investments
for the three-year period ended December 31,
2021, totaled
$16.7 billion.
The 2021 expenditures supported
key exploration
and developments, primarily:
●
Development activities in the Lower 48, primarily Permian,
Eagle Ford, and Bakken.
●
Appraisal and development activities in Alaska
related to the Western
North Slope and development
activities in the Greater Kuparuk Area.
●
Appraisal and development activities in the
Montney and optimization of oil sands
development in
Canada.
●
Continued development activities across
assets in Norway.
●
Continued development activities in China,
Malaysia, and Indonesia.
2022 Capital Budget
In December 2021, we announced our 2022 operating plan
capital of $7.2 billion.
The plan includes funding for
ongoing development drilling programs,
major projects, exploration and
appraisal activities, base maintenance and
$0.2 billion for projects to reduce
the company’s scope
1 and 2 emissions intensity and investments
in several
early-stage low-carbon
opportunities that address end-use emissions.
Capital Resources and Liquidity
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57
ConocoPhillips
2021 10-K
Guarantor Summarized Financial
Information
We have various
cross guarantees among ConocoPhillips,
ConocoPhillips Company,
and Burlington Resources LLC
with respect to publicly held debt securities.
ConocoPhillips Company is 100 percent
owned by ConocoPhillips.
Burlington Resources LLC is
100 percent owned by ConocoPhillips Company.
ConocoPhillips and/or ConocoPhillips
Company have fully and unconditionally
guaranteed the payment obligations
of Burlington Resources LLC with
respect to its publicly held debt securities.
Similarly, ConocoPhillips
has fully and unconditionally guaranteed the
payment obligations of ConocoPhillips
Company with respect to its publicly held
debt securities.
In addition,
ConocoPhillips Company has fully and unconditionally
guaranteed the payment obligations
of ConocoPhillips with
respect to its publicly held debt securities.
All guarantees are joint and
several.
The following tables present summarized
financial information for
the Obligor Group, as defined below:
●
The Obligor Group will reflect guarantors
and issuers of guaranteed securities consisting
of
ConocoPhillips, ConocoPhillips Company
and Burlington Resources LLC.
●
Consolidating adjustments for elimination
of investments in and transactions
between the collective
guarantors and issuers
of guaranteed securities are reflected
in the balances of the summarized financial
information.
●
Non-Obligated Subsidiaries are exclud
ed from this presentation.
Upon completing the Concho acquisition on January 15, 2021, we assumed
Concho’s publicly traded
debt of
approximately $3.9 billion in aggregate
principal amount, which was recorded
at the fair value of $4.7 billion on
the acquisition date.
We completed a debt exchange
offer that settled
on February 8, 2021, of which 98 percent,
or approximately $3.8 billion in
aggregate principal amount of Concho’s
notes, were tendered and accepted
for
new debt issued by ConocoPhillips.
The new debt issued in the exchange is fully and
unconditionally guaranteed
by ConocoPhillips Company.
Both the guarantor and issuer of the exchange
debt is reflected within the Obligor
Group presented here.
See Note 3
and
Note 9
.
Transactions
and balances reflecting activity between the Obligors
and Non-Obligated Subsidiaries
are presented
separately below:
Summarized Income Statement
Data
Millions of Dollars
2021
Revenues and Other Income
$
30,457
Income (loss) before income taxes*
8,017
Net income (loss)
8,079
Net Income (Loss) Attributable
to ConocoPhillips
8,079
*Includes approximately $5.4 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.
Summarized Balance Sheet Data
Millions of Dollars
December 31, 2021
Current assets
$
7,689
Amounts due from Non-Obligated Subsidiaries, current
1,927
Noncurrent assets
69,841
Amounts due from Non-Obligated Subsidiaries, noncurrent
7,281
Current liabilities
8,005
Amounts due to Non-Obligated Subsidiaries,
current
3,477
Noncurrent liabilities
30,677
Amounts due to Non-Obligated Subsidiaries,
noncurrent
13,007
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58
Contingencies
We are subject to legal proceedings,
claims, and liabilities that arise in the ordinary course of business.
We accrue
for losses associated with legal
claims when such losses are considered probable
and the amounts can be
reasonably estimated.
See “Critical Accounting Estimates”
and
Note 11
for information on contingencies.
Legal and Tax
Matters
We are subject to various
lawsuits and claims, including but not limited to matters
involving oil and gas royalty
and
severance tax payments,
gas measurement and valuation
methods, contract disputes,
environmental damages,
climate change, personal injury,
and property damage.
Our primary exposures for such matters
relate to alleged
royalty and tax underpayments
on certain federal, state
and privately owned properties,
claims of alleged
environmental contamination
and damages from historic operations,
and climate change.
We will continue to
defend ourselves vigorously
in these matters.
Our legal organization
applies its knowledge, experience, and professional
judgment to the specific characteristics
of our cases, employing a litigation management
process to manage and monitor the legal
proceedings against us.
Our process facilitates the
early evaluation and quantification
of potential exposures in individual cases.
This
process also enables us to track those cases
that have been scheduled for trial and/or
mediation.
Based on
professional judgment and experience
in using these litigation management
tools and available information
about
current developments in all our cases,
our legal organization regularly
assesses the adequacy of current accruals
and determines if an adjustment of existing
accruals, or establishment of new accruals, is
required.
See Note 17
.
Environmental
We are subject to the same numerous
international, federal,
state, and local environmental
laws and regulations
as other companies in our industry.
The most significant of these environmental
laws and regulations include,
among others, the:
●
U.S. Federal Clean Air Act, which governs
air emissions.
●
U.S. Federal Clean Water
Act, which governs discharges
to water bodies.
●
European Union Regulation for
Registration, Evaluation,
Authorization and Restriction of Chemicals
(REACH).
●
U.S. Federal Comprehensive
Environmental Response,
Compensation and Liability Act (CERCLA or
Superfund), which imposes liability on generators,
transporters and arrangers
of hazardous substances at
sites where hazardous substance
releases have occurred or are
threatening to occur.
●
U.S. Federal Resource
Conservation and Recovery
Act (RCRA), which governs the treatment,
storage, and
disposal of solid waste.
●
U.S. Federal Oil Pollution Act
of 1990 (OPA90), under which
owners and operators
of onshore facilities
and pipelines, lessees or permittees of an area in which an
offshore facility is located,
and owners and
operators of vessels
are liable for removal costs
and damages that result from a discharge
of oil into
navigable waters
of the U.S.
●
U.S. Federal Emergency Planning
and Community Right-to-Know Act (EPCRA),
which requires facilities to
report toxic chemical inventories
with local emergency planning committees
and response departments.
●
U.S. Federal Safe Drinking
Water Act, which governs
the disposal of wastewater
in underground injection
wells.
●
U.S. Department of the Interior regulations,
which relate to offshore oil and
gas operations in U.S. waters
and impose liability for the cost of pollution
cleanup resulting from operations, as
well as potential liability
for pollution damages.
●
European Union Trading
Directive resulting in European
Emissions Trading Scheme.
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59
ConocoPhillips
2021 10-K
These laws and their implementing regulations
set limits on emissions and, in the case of discharges
to water,
establish water quality limits, and
establish standards and impose obligations
for the remediation of releases of
hazardous substances
and hazardous wastes.
They also, in most cases, require permits
in association with new or
modified operations.
These permits can require an applicant
to collect substantial information
in connection with
the application process, which can be expensive
and time-consuming.
In addition, there can be delays associated
with notice and comment periods and the agency’s
processing of the application.
Many of the delays associated
with the permitting process are beyond
the control of the applicant.
Many states and foreign
countries where we operate
also have or are developing, similar environmental
laws and
regulations governing these same types of activities.
While similar,
in some cases these regulations may impose
additional, or more stringent, requirements
that can add to the cost and difficulty
of marketing or transporting
products across state
and international borders.
The ultimate financial impact arising from environmental
laws and regulations is neither clearly known
nor easily
determinable as new standards,
such as air emission standards and water
quality standards, continue to
evolve.
However,
environmental laws
and regulations, including those that may
arise to address concerns about global
climate change, are expected
to continue to have an
increasing impact on our operations in the U.S. and
in other
countries in which we operate.
Notable areas of potential impacts include
air emission compliance and
remediation obligations in the U.S.
and Canada.
An example is the use of hydraulic
fracturing, an essential completion technique that
facilitates production
of oil
and natural gas otherwise trapped
in lower permeability rock formations.
A range of local, state,
federal,
or
national laws and regulations currently
govern hydraulic
fracturing operations, with hydraulic
fracturing currently
prohibited in some jurisdictions.
Although hydraulic fracturing has
been conducted for many decades,
a number of
new laws, regulations and permitting requirements
are under consideration by
various state environmental
agencies, and others which could result
in increased costs, operating restrictions,
operational delays and/or
limit
the ability to develop oil and natural
gas resources.
Governmental restrictions on hydraulic
fracturing could impact
the overall profitability or viability
of certain of our oil and natural gas
investments.
We have adopted
operating
principles that incorporate
established industry standards
designed to meet or exceed government
requirements.
Our practices continually evolve
as technology improves and regulations
change.
We also are subject to certain
laws and regulations relating to
environmental remediation
obligations associated
with current and past operations.
Such laws and regulations include CERCLA and RCRA
and their state equivalents.
Longer-term expenditures are
subject to considerable uncertainty
and may fluctuate significantly.
We occasionally receive requests
for information or notices of potential
liability from the EPA
and state
environmental agencies alleging
that we are a potentially responsible
party under CERCLA or an equivalent state
statute.
On occasion, we also have been made a party to
cost recovery litigation by
those agencies or by private
parties.
These requests, notices and lawsuits
assert potential liability for remediation
costs at various sites that
typically are not owned by us, but allegedly contain
wastes attributable to
our past operations.
As of
December 31, 2021, there were 15 sites around
the U.S. in which we were identified as a
potentially responsible
party under CERCLA and comparable state
laws.
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60
For most Superfund sites, our potential
liability will be significantly less than the total
site remediation costs
because the percentage of waste
attributable to us, versus
that attributable to all other potentially
responsible
parties, is relatively low.
Although liability of those potentially responsible
is generally joint and several
for federal
sites and frequently so for state
sites, other potentially responsible parties
at sites where we are a party typically
have had the financial strength
to meet their obligations, and where they
have not, or where potentially
responsible parties could not be located,
our share of liability has not increased materially.
Many of the sites at
which we are potentially responsible
are still under investigation
by the EPA
or the state agencies concerned.
Prior
to actual cleanup, those potentially responsible
normally assess site conditions, apportion responsibility
and
determine the appropriate remediation.
In some instances, we may have
no liability or attain a settlement
of
liability.
Actual cleanup costs generally occur after
the parties obtain EPA
or equivalent state agency approval.
There are relatively few
sites where we are a major participant,
and given the timing and amounts of anticipated
expenditures, neither the cost of remediation
at those sites nor such costs at
all CERCLA sites, in the aggregate, is
expected to have a material
adverse effect on
our competitive or financial condition.
Expensed environmental costs
were $632 million in 2021 and are expected
to be about $642 million and
$700 million in 2022 and 2023, respectively.
Capitalized environmental
costs were $184 million in 2021 and are
expected to be about $218 million and $316 million in
2022 and 2023, respectively.
Accrued liabilities for remediation activities
are not reduced for potential recoveries
from insurers or other third
parties and are not discounted (except
those assumed in a purchase business combination,
which we do record on
a discounted basis).
Many of these liabilities result from CERCLA, RCRA
,
and similar state or international
laws that require us to
undertake certain investigative
and remedial activities at sites where we conduct
or once conducted operations
or
at sites where ConocoPhillips-generated
waste was disposed.
The accrual also includes a number of sites we
identified that may require environmental
remediation but which are not currently
the subject of CERCLA, RCRA,
or other agency enforcement activities.
The laws that require or address
environmental remediation
may apply
retroactively and regardless
of fault, the legality of the original activities or the current
ownership or control of
sites.
If applicable, we accrue receivables for probable
insurance or other third-party recoveries.
In the future, we
may incur significant costs under both
CERCLA and RCRA.
Remediation activities vary substantially
in duration and cost from site to
site, depending on the mix of unique site
characteristics, evolving remediation
technologies, diverse regulatory
agencies and enforcement policies,
and the
presence or absence of potentially liable third
parties.
Therefore, it is difficult to develop
reasonable estimates of
future site remediation costs.
At December 31, 2021, our balance sheet included total
accrued environmental costs
of $187 million, compared
with $180 million at December 31, 2020, for remediation
activities in the U.S. and Canada.
We expect to incur a
substantial amount of these expenditures
within the next 30 years.
Notwithstanding any of the foregoing,
and as with other companies engaged in similar businesses,
environmental
costs and liabilities are inherent
concerns in our operations and products,
and there can be no assurance that
material costs and liabilities will not be incurred.
However,
we currently do not expect any material
adverse effect
upon our results of operations or financial position
as a result of compliance with current environmental
laws and
regulations.
See Item 1A—Risk Factors – We expect to continue to incur substantial capital expenditures and operating costs as
a result of our compliance with existing and future environmental laws and regulations
and
Note 11
for information
on environmental litigatio
n.
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61
ConocoPhillips
2021 10-K
Climate Change
Continuing political and social attention
to the issue of global climate change has resulted
in a broad range of
proposed or promulgated
state, national and international
laws focusing on GHG reduction.
These proposed or
promulgated laws apply
or could apply in countries where we have
interests or may have
interests in the future.
Laws in this field continue to evolve,
and while it is not possible to accurately estimate
either a timetable for
implementation or our future compliance costs
relating to implementation, such
laws, if enacted, could have a
material impact on our results of operations
and financial condition.
Examples of legislation and precursors
for
possible regulation that do or could affect
our operations include:
●
European Emissions Trading
Scheme (ETS), the program through
which many of the EU member states are
implementing the Kyoto Protocol.
Our cost of compliance with the EU ETS in 2021 was
approximately $19
million (net share before-tax
).
●
U.K. Emissions Trading
Scheme, the program with which the U.K. has
replaced the ETS.
Our cost of
compliance with the U.K. ETS in 2021 was approximately
$2.8 million (net share before
-tax).
●
The Alberta Technology
Innovation and Emissions Reduction
(TIER) regulation requires any
existing facility
with emissions equal to or greater than 100,000 metric
tonnes of carbon dioxide, or equivalent,
per year
to meet a facility benchmark intensity.
The total cost of these regulations in 2021 was
approximately $1
million (net share before-tax)
.
●
The U.S. Supreme Court decision in Massachusetts
v. EPA,
549 U.S. 497, 127 S.Ct. 1438 (2007), confirmed
that the EPA
has the authority to regulate carbon dioxide
as an “air pollutant” under the Federal Clean Air
Act.
●
The U.S. EPA’s
announcement on March 29, 2010 (published as “Interpretation
of Regulations that
Determine Pollutants Covered
by Clean Air Act Permitting Programs,”
75 Fed. Reg. 17004 (April 2, 2010)),
and the EPA’s
and U.S. Department of Transportation’s
joint promulgation of a Final Rule on April 1, 2010,
that triggers regulation of GHGs under
the Clean Air Act, may trigger more climate-based
claims for
damages, and may result in longer agency review
time for development projects.
●
The U.S. EPA’s
announcement on January 14, 2015, outlining a series of steps
it plans to take to address
methane and smog-forming volatile
organic compound emissions from the
oil and gas industry.
●
The U.S. government has announced
on September 17, 2021 the Global Methane Pledge,
a global
initiative to reduce global methane emissions
by at least 30 percent from 2020 levels
by 2030.
●
Carbon taxes in certain jurisdictions.
Our cost of compliance with Norwegian carbon legislation
in 2021
were fees of approximately
$35 million (net share before
-tax).
We also incur a carbon tax for
emissions
from fossil fuel combustion in our
British Columbia and Alberta operations in Canada,
totaling
approximately $5.7 million (net
share before-tax).
●
The agreement reached in Paris
in December 2015 at the 21
st
Conference of the Parties to
the United
Nations Framework Convention
on Climate Change, setting out a process
for achieving global emission
reductions.
The new administration has recommitted
the United States to the Paris
Agreement, and a
significant number of U.S. state
and local governments and major corporations
headquartered in the U.S.
have also announced related commitments.
Accordingly,
the U.S. administration set
a new target on
April 22, 2021 of a 50 to 52 percent reduction
in GHG emissions from 2005 levels in 2030.
In the U.S., some additional form of regulation
may be forthcoming in the future at
the federal and state
levels
with respect to GHG emissions.
Such regulation could take
any of several forms that
may result in the creation of
additional costs in the form of taxes,
the restriction of output, investments
of capital to maintain compliance with
laws and regulations, or required
acquisition or trading of emission allowances.
We are working to continuously
improve operational and energy
efficiency through resource and
energy conservation throughout
our operations.
Capital Resources and Liquidity
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62
Compliance with changes in laws and regulations
that create a GHG tax, emission trading
scheme or GHG
reduction policies could significantly increase
our costs, reduce demand for fossil
energy derived products, impact
the cost and availability of capital
and increase our exposure to litigation.
Such laws and regulations could also
increase demand for less carbon intensive
energy sources, including natural
gas.
The ultimate impact on our
financial performance, either positive or negative,
will depend on a number of factors, including but
not limited to:
●
Whether and to what extent legislation
or regulation is enacted.
●
The timing of the introduction of such legislation or
regulation.
●
The nature of the legislation (such as a cap and trade
system or a tax on emissions)
or regulation.
●
The price placed on GHG emissions (either by the market
or through a tax).
●
The GHG reductions required.
●
The price and availability of offsets.
●
The amount and allocation of allowances.
●
Technological
and scientific developments leading to new products
or services.
●
Any potential significant physical
effects of climate change (such
as increased severe weather events,
changes in sea levels and changes in temperature).
●
Whether,
and the extent to which, increased compliance
costs are ultimately reflected
in the prices of our
products and services.
See Item 1A—Risk Factors – Existing and future laws, regulations and internal initiatives relating to global climate
changes, such as limitations on GHG emissions may impact or limit our business plans, result in significant
expenditures, promote alternative uses of energy or reduce demand for our products
and
Note 11
for information
on climate change litigation.
Company Response to Climate
-Related Risks
The company has responded by putting
in place a Sustainable Development Risk Management
Standard covering
the assessment and registration
of significant and high sustainable development
risks based on their consequence
and likelihood of occurrence.
We have developed a
company-wide Climate Change Action
Plan with the goal of
tracking mitigation activities for
each climate-related risk included in the corporate
Sustainable Development Risk
Register.
The risks addressed in our Climate Change Action
Plan fall into four broad
categories:
●
GHG-related legislation and regulation.
●
GHG emissions management.
●
Physical climate-related
impacts.
●
Climate-related disclosure
and reporting.
Emissions are categorized
into three different
scopes.
Gross operated and net
equity Scope 1 and Scope 2 GHG
emissions help us understand our climate
transition risk.
●
Scope 1 emissions are direct GHG emissions from
sources that we control
or in which we have
ownership interest.
●
Scope 2 emissions are indirect GHG emissions
from the generation of purchased
electricity or steam that
we consume.
●
Scope 3 emissions are indirect emissions from
sources that we neither own nor control.
Capital Resources and Liquidity
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We announced in October 2020 the adoption
of a Paris-aligned climate risk framework
with the objective of
implementing a coherent set of choices designed
to facilitate the success
of our existing exploration
and
production business through the energy transition.
Given the uncertainties remaining about
how the energy
transition will evolve, the strategy
aims to be robust across a range
of potential future outcomes.
The strategy is comprised of four
pillars:
●
Targets
:
Our target framework
consists of a hierarchy
of targets, from a long-term ambition
that sets the
direction and aim of the strategy,
to a medium-term performance target
for GHG emissions intensity,
to
shorter-term targets for
flaring and methane intensity reductions.
These performance targets are
supported by lower-level internal
business unit goals to enable the company to
achieve the company-
wide targets.
In September 2021, we increased our interim
operational target and
have set it to reduce
our gross operated and net
equity (scope 1 and 2) emissions intensity by
40 to 50 percent from 2016
levels by 2030, an improvement
from the previously announced target
of 35 to 45 percent on only a gross
operated basis, with an ambition to
achieve net-zero operated
emissions by 2050.
We have joined the
World Bank Flaring Initiative to
work towards zero
routine flaring of associated gas
by 2030, with an
ambition to meet that goal by 2025.
●
Technology choices:
We expanded our Marginal
Abatement Cost Curve process
to provide a broader
range of opportunities for emission
reduction technology.
●
Portfolio choices: Our corporate
authorization process requires
all qualifying projects to include a GHG
price in their project approval economics.
Different GHG prices are used
depending on the region or
jurisdiction.
Projects in jurisdictions with existing GHG pricing regimes
incorporate the existing
GHG price
and forecast into
their economics.
Projects where no existing GHG pricing regime
exists utilize a scenario
forecast from our internally
consistent World
Energy Model.
In this way,
both existing and emerging
regulatory requirements are
considered in our decision-making.
The company does not use an estimated
market cost of GHG emissions when assessing
reserves in jurisdictions without existing GHG regulations
.
This is in contrast to changes
to the cost of existing GHG emission
regulations which can impact our
reserves calculations.
●
External engagement: Our external
engagement aims to differentiate
ConocoPhillips within the oil and
gas sector with our approach to managing
climate-related risk.
We are a Founding Member of the
Climate Leadership Council (CLC), an international
policy institute founded in collaboration
with business
and environmental interests
to develop a carbon dividend plan.
Participation in the CLC provides
another
opportunity for ongoing dialogue about carbon
pricing and framing the issues in alignment with our
public
policy principles.
We also belong to and fund Americans For
Carbon Dividends, the education and
advocacy branch of the CLC.
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64
Critical Accounting Estimates
The preparation of financial statements
in conformity with GAAP requires
management to select appropriate
accounting policies and to make
estimates and assumptions that
affect the reported amounts
of assets, liabilities,
revenues and expenses.
See Note 1
for descriptions of our major accounting policies.
Certain of these accounting
policies involve judgments and uncertainties
to such an extent there is a reasonable
likelihood materially different
amounts would have been reported
under different conditions,
or if different assumptions had been
used.
These
critical accounting estimates are
discussed with the Audit and Finance Committee of the Board
of Directors at least
annually.
We believe the following discussions
of critical accounting estimates address
all important accounting
areas where the nature of accounting
estimates or assumptions is material
due to the levels of subjectivity and
judgment necessary to account for
highly uncertain matters or
the susceptibility of such matters to
change.
Oil and Gas Accounting
Accounting for oil and gas activity
is subject to special accounting rules unique to the oil
and gas industry.
The
acquisition of G&G seismic information, prior to
the discovery of proved reserves,
is expensed as incurred, similar
to accounting for research
and development costs.
However,
leasehold acquisition costs and exploratory
well
costs are capitalized
on the balance sheet pending determination of whether
proved oil and gas reserves
have
been recognized.
Property Acquisition Costs
At year-end 2021, we held $9.3 billion
of net capitalized unproved
property costs which consisted
primarily of
individually significant and pooled leaseholds, mineral
rights held in perpetuity by title ownership,
exploratory
wells currently being drilled, and to a lesser
extent, suspended exploratory
wells and capitalized interest.
This
amount increased by $6.9 billion at December 31, 2021 as compared
to December 31, 2020, primarily due to the
Concho and Shell Permian acquisitions
in the Permian Basin where we have an ongoing
significant and active
development program.
Outside of the Permian Basin, the remaining
$2.0 billion is concentrated
in 9 major
development areas.
Management periodically assesses our unproved
property for impairment based on the
results of exploration and
drilling efforts and the outlook for commercialization.
For individually significant leaseholds, management
periodically assesses for impairment based
on exploration and
drilling efforts to date.
For insignificant individual leasehold acquisition
costs, management exercises
judgment
and determines a percentage probability
that the prospect ultimately will fail to
find proved oil and gas reserves,
including estimates of future expirations,
and pools that leasehold information with others
in similar geographic
areas.
For prospects in areas with limited, or
no, previous exploratory
drilling, the percentage probability of
ultimate failure is normally judged
to be quite high.
This judgmental percentage is multiplied
by the leasehold
acquisition cost, and that product is
divided by the contractual period of the leasehold to
determine a periodic
leasehold impairment charge that is
reported in exploration expense.
This judgmental probability percentage
is
reassessed and adjusted throughout
the contractual period of the leasehold based on favorable
or unfavorable
exploratory activity on the leasehold or
on adjacent leaseholds, and leasehold impairment amortization
expense is
adjusted prospectively.
Exploratory Costs
For exploratory wells, drilling
costs are temporarily capitalized,
or “suspended,”
on the balance sheet, pending a
determination of whether potentially economic
oil and gas reserves have
been discovered by the drilling effort
to
justify development.
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If exploratory wells encounter
potentially economic quantities of oil and gas,
the well costs remain capitalized
on
the balance sheet as long as sufficient progress
assessing the reserves and the economic and operating
viability of
the project is being made.
The accounting notion of “sufficient
progress” is a judgmental area,
but the accounting
rules do prohibit continued capitalization
of suspended well costs on the expectation
future market conditions will
improve or new technologies will be found
that would make the development
economically profitable.
Often, the
ability to move into the development
phase and record proved
reserves is dependent on obtaining permits and
government or co-venturer
approvals, the timing of which is ultimately
beyond our control.
Exploratory well costs
remain suspended as long as we are actively pursuing
such approvals and permits, and believe they will be
obtained.
Once all required approvals
and permits have been obtained, the projects
are moved into the
development phase, and the oil and gas
reserves are designated as proved
reserves.
At year-end 2021, total suspended
well costs were $660 million, compared
with $682 million at year-end 2020.
For additional information on suspended
wells, including an aging analysis,
see Note 6
.
Proved Reserves
Engineering estimates of the quantities of proved
reserves are inherently imprecise and
represent only
approximate amounts because
of the judgments involved in developing
such information.
Reserve estimates are
based on geological and engineering assessments of in-place
hydrocarbon volumes,
the production plan, historical
extraction recovery and processing
yield factors, installed plant
operating capacity and approved
operating limits.
The reliability of these estimates at
any point in time depends on both the quality and quantity
of the technical and
economic data and the efficiency of extracting
and processing the hydrocarbons.
Despite the inherent imprecision in
these engineering estimates, accounting
rules require disclosure of “proved”
reserve estimates due to the importance
of these estimates to better
understand the perceived value
and future
cash flows of a company’s
operations.
There are several authoritative
guidelines regarding the engineering criteria
that must be met before estimated
reserves can be designated as “proved.”
Our geosciences and reservoir
engineering organization has
policies and procedures in place consistent
with these authoritative guidelines.
We
have trained and experienced
internal engineering personnel who estimate
our proved reserves held by
consolidated companies, as well as our share
of equity affiliates.
See Oil and Gas supplemental disclosures for
additional information.
Proved reserve estimates are
adjusted annually in the fourth quarter
and during the year if significant changes
occur, and
take into account
recent production and subsurface information
about each field.
Also, as required by
current authoritative guidelines,
the estimated future date
when an asset will reach the end of its economic life is
based on 12-month average prices
and current costs.
This date estimates when production
will end and affects
the amount of estimated reserves.
Therefore, as prices and cost
levels change from year to year,
the estimate of
proved reserves also changes.
Generally, our
proved reserves decrease as prices
decline and increase as prices
rise.
Our proved reserves include estimat
ed quantities related to PSCs, reported
under the “economic interest”
method, as well as variable-royalty
regimes, and are subject to fluctuations
in commodity prices; recoverable
operating expenses; and capital
costs.
If costs remain stable, reserve quantities
attributable to recovery of costs
will change inversely to changes
in commodity prices.
We would expect reserves
from these contracts to
decrease
when product prices rise and increase when prices decline.
The estimation of proved reserves
is also important to the income statement
because the proved reserve estimate
for a field serves as the denominator in the unit-of-production
calculation of the DD&A of the capitalized costs
for that asset.
At year-end 2021, the net book value of productive
PP&E subject to a unit-of-production
calculation
was approximately $52 billion
and the DD&A recorded on these assets in
2021 was approximately $7.0 billion.
The
estimated proved reserves
for our consolidated operations
were 2.5 billion BOE at the end of 2020 and 4.0 billion
BOE at the end of 2021.
If the estimates of proved reserves
used in the unit-of-production
calculations had been
lower by 10 percent across all calculations,
before-tax DD&A in 2021 would have
increased by an estimated
$774 million.
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66
Business Combination—Valuation
of Oil and Gas Properties
For recent transactions, management
applied the principles of acquisition accounting under FASB
ASC Topic 805
–
“Business Combinations” and allocated the purchase
price to assets acquired and liabilities assumed, based
on
their estimated fair values as
of the acquisition date.
Estimating the fair values involved
making various
assumptions, of which the most significant assumptions
relate to the fair values assigned
to proved and unproved
oil and gas properties.
Management utilized a discounted
cash flow approach, based on market participant
assumptions, and engaged third party
valuation experts in preparing fair value
estimates.
Significant inputs incorporated
within the valuation include future commodity price assumptions
and production
profiles of reserve estimates, the
pace of drilling plans, future operating and development
costs, inflation rates,
and discount rates using a market
-based weighted average
cost of capital determined at the
time of the
acquisition.
When estimating the fair value of unproved
properties, additional risk-weighting
adjustments are
applied to probable and possible reserves.
The assumptions and inputs incorporated
within the fair value estimates are
subject to considerable management
judgement and are based on industry,
market, and economic conditions prevalent
at the time of the acquisition.
Although we based these estimates on assumptions
believed to be reasonable, these estimates
are inherently
unpredictable and uncertain and actual results
could differ.
See Note 3
.
Impairments
Long-lived assets used in operations
are assessed for impairment whenever changes
in facts and circumstances
indicate a possible significant deterioration
in the future cash flows expected
to be generated by an
asset group.
If
there is an indication the carrying amount
of an asset may not be recovered,
a recoverability test
is performed
using management’s assumptions
for prices, volumes and future development
plans.
If the sum of the
undiscounted cash flows before
income-taxes is less than
the carrying value of the asset group, the carrying
value
is written down to estimated fair
value and reported as an impairment
in the periods in which the determination is
made.
Individual assets are grouped for
impairment purposes at the lowest level for
which there are identifiable
cash flows that are largely independent
of the cash flows of other groups of assets—generally
on a field-by-field
basis for E&P assets.
Because there usually is a lack of quoted market
prices for long-lived assets, the fair
value of
impaired assets is typically determined based
on the present values of expected
future cash flows using discount
rates and prices believed to
be consistent with those used by principal
market participants, or based on a multiple
of operating cash flow validated
with historical market transactions
of similar assets where possible.
The expected future cash flows used
for impairment reviews and
related fair value calculations
are based on
estimated future production volumes,
commodity prices, operating costs
and capital decisions, considering all
available evidence at the date of review.
Differing assumptions could
affect the timing and the amount of an
impairment in any period.
See
Note 6
and
Note 7
.
Investments in nonconsolidated
entities accounted for under the equity
method are assessed for impairment
whenever changes in the facts and circumstances
indicate a loss in value has occurred.
Such evidence of a loss in
value might include our inability to recover
the carrying amount, the lack of sustained earnings
capacity which
would justify the current investment
amount, or a current fair value
less than the investment’s
carrying amount.
When such a condition is judgmentally determined
to be other than temporary,
an impairment charge is
recognized for the difference
between the investment’s
carrying value and its estimated fair
value.
When
determining whether a decline in value is other than
temporary,
management considers factors
such as the length
of time and extent of the decline, the investee’s
financial condition and near-term prospects,
and our ability and
intention to retain our
investment for a period that
will be sufficient to allow for any
anticipated recovery in the
market value of the investment.
Since quoted market prices are usually
not available, the fair value is typically
based on the present value of expected future
cash flows using discount
rates and prices believed to be consistent
with those used by principal market participants,
plus market analysis of comparable
assets owned by the
investee, if appropriate.
Differing assumptions could affect
the timing and the amount of an impairment of an
investment in any period.
See the “APLNG” section
of
Note 4
.
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Asset Retirement Obligations
and Environmental Costs
Under various contracts, permits
and regulations, we have material
legal obligations to remove
tangible
equipment and restore the land or
seabed at the end of operations at operational
sites.
Our largest asset removal
obligations involve
plugging and abandonment of wells, removal and disposal
of offshore oil and gas platforms
around the world, as well as oil and gas
production facilities and pipelines in Alaska.
Fair value is estimated using
a
present value approach,
incorporating assumptions about estimated
amounts and timing of settlements and
impacts of the use of technologies.
Estimating future asset removal
costs requires significant
judgement.
Most of
these removal obligations are
many years, or decades,
in the future and the contracts and regulations
often have
vague descriptions of what removal
practices and criteria must be met when the removal
event actually occurs.
The carrying value of our asset retirement
obligation estimate is sensitive
to inputs such as asset removal
technologies and costs, regulatory
and other compliance considerations,
expenditure timing, and other inputs into
valuation of the obligation,
including discount and inflation rates,
which are all subject to change between the time
of initial recognition of the liability and future settlement
of our obligation.
Normally, changes
in asset removal obligations
are reflected in the income statement
as increases or decreases to
DD&A over the remaining life of the assets.
However,
for assets at or nearing the end of their operations,
as well
as previously sold assets for which we retained
the asset removal obligation,
an increase in the asset removal
obligation can result in an immediate charge
to earnings, because any increase
in PP&E due to the increased
obligation would immediately
be subject to impairment, due to the low fair value
of these properties.
In addition to asset removal obligations,
under the above or similar contracts, permits
and regulations, we have
certain environmental-related
projects.
These are primarily related to remediation
activities required by Canada
and various states within the U.S.
at exploration and production
sites.
Future environmental remediation
costs are
difficult to estimate because they
are subject to change due to such factors
as the uncertain magnitude of cleanup
costs, the unknown time and extent of such
remedial actions that may be required,
and the determination of our
liability in proportion to that of other responsible
parties.
See Note 8
.
Projected Benefit Obligations
The actuarial determination of projected benefit
obligations and company
contribution requirements involves
judgment about uncertain future events,
including estimated retirement
dates, salary levels at retirement,
mortality rates, lump-sum election rates,
rates of return on plan assets,
future health care cost-trend rates,
and
rates of utilization of health
care services by retirees.
Due to the specialized nature of these
calculations, we
engage outside actuarial firms to assist
in the determination of these projected benefit
obligations and company
contribution requirements.
Ultimately,
we will be required to fund all vested
benefits under pension and
postretirement benefit plans
not funded by plan assets or investment
returns, but the judgmental assumptions
used in the actuarial calculations significantly affect
periodic financial statements and
funding patterns over time.
Projected benefit obligations
are particularly sensitive to the discount
rate assumption.
A 100 basis-point decrease
in the discount rate assumption
would increase projected benefit obligations
by $1.0 billion.
Benefit expense is
sensitive to the discount rate
and return on plan assets assumptions.
A 100 basis-point decrease in the discount
rate assumption would increase
annual benefit expense by $70 million, while a 100 basis-point
decrease in the
return on plan assets assumption would increase
annual benefit expense by $60 million.
In determining the
discount rate, we use yields
on high-quality fixed income investments
matched to the estimated benefit
cash flows
of our plans.
We are also exposed to the possibility
that lump sum retirement benefits taken
from pension plans
during the year could exceed the
total of service and interest components
of annual pension expense and
trigger accelerated recognition
of a portion of unrecognized net actuarial
losses and gains.
These benefit
payments are based on decisions by plan
participants and are therefore difficult
to predict.
In the event there is a
significant reduction in the expected years
of future service of present employees or the elimination
of the accrual
of defined benefits for some or all of their future
services for a significant number of employees,
we could
recognize a curtailment gain
or loss.
See Note 16
.
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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 11
.
Income Taxes
We are subject to income taxation
in numerous jurisdictions worldwide.
We record deferred
tax assets and
liabilities to account for the expected
future tax consequences of events
that have been recognized
in our financial
statements and our tax
returns.
We routinely assess our deferred
tax assets and reduce such assets
by a valuation
allowance if we deem it is more likely than
not that some portion,
or all, of the deferred tax assets
will not be
realized.
In assessing the need for adjustments
to existing valuation allowances,
we consider all available positive
and negative evidence.
Positive evidence includes reversals
of temporary differences,
forecasts of future taxable
income, assessment of future business assumptions
and applicable tax planning strategies
that are prudent and
feasible.
Negative evidence includes losses
in recent years as well as the forecasts
of future net income (loss) in
the realizable period.
In making our assessment regarding
valuation allowances, we weight
the evidence based on
objectivity.
Numerous judgments and assumptions are
inherent in the determination of future taxable
income,
including factors such as future operating
conditions and the assessment of the effects
of foreign taxes
on our U.S.
federal income taxes
(particularly as related to prevai
ling oil and gas prices).
See Note 17
.
We regularly assess and, if required,
establish accruals for uncertain tax
positions that could result from
assessments of additional tax by taxing
jurisdictions in countries where we operate.
We recognize a tax
benefit
from an uncertain tax position when it
is more likely than not that the
position will be sustained upon examination,
based on the technical merits of the position.
These accruals for uncertain tax positions
are subject to a significant
amount of judgment and are reviewed
and adjusted on a periodic basis in light of changing facts
and
circumstances considering the progress
of ongoing tax audits, court proceedings,
changes in applicable tax laws,
including tax case rulings and legislative guidance,
or expiration of the applicable statute
of limitations.
See Note
17
regarding discussion of critical accounting
estimates on deferred
tax valuation allowances.
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Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the
Private Securities Litigation Reform Act
of 1995
This report includes forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934.
All statements other than
statements of historical
fact
included or incorporated by
reference in this report, including, without
limitation, statements
regarding our future
financial position, business strategy,
budgets, projected revenues,
projected costs and plans, objectives
of
management for future operatio
ns and the anticipated impact of the Shell Enterprise
LLC (Shell) transaction on the
company’s business
and future financial and operating results are
forward-looking statements.
Examples of
forward-looking statements
contained in this report include our expected
production growth and outlook
on the
business environment generally,
our expected capital budget and
capital expenditures, and discussions
concerning
future dividends.
You can often identify
our forward-looking statements
by the words “anticipate,”
“believe,”
“budget,”
“continue,”
“could,”
“effort,”
“estimate,”
“expect,”
“forecast,”
“intend,”
“goal,”
“guidance,”
“may,”
“objective,”
“outlook,”
“plan,” “potential,”
“predict,” “projection,”
“seek,”
“should,”
“target,”
“will,” “would” and
similar expressions.
We based the forward-looking
statements on our current
expectations, estimates and
projections about ourselves
and the industries in which we operate in
general.
We caution you these
statements are not guarantees
of future
performance as they involve
assumptions that, while made in good faith, may
prove to be incorrect, and involve
risks and uncertainties we cannot predict.
In addition, we based many of these forward
-looking statements on
assumptions about future events
that may prove to be inaccurate.
Accordingly,
our actual outcomes and results
may differ materially from
what we have expressed
or forecast in the forward
-looking statements.
Any differences
could result from a variety of factors
and uncertainties, including, but not limited to,
the following:
●
The impact of public health crises, including pandemics (such as COVID
-19) and epidemics and any related
company or government policies
or actions.
●
Global and regional changes in the demand, supply,
prices, differentials or other market
conditions
affecting oil and gas, including changes
resulting from a public health crisis or from the imposition
or
lifting of crude oil production quotas or other actions
that might be imposed by OPEC and other producing
countries and the resulting company
or third-party actions in response to such changes.
●
Fluctuations in crude oil, bitumen, natural gas,
LNG and NGLs prices, including a prolonged decline in
these prices relative to historical
or future expected levels.
●
The impact of significant declines in prices for crude
oil, bitumen, natural gas, LNG and
NGLs, which may
result in recognition of impairment charges
on our long-lived assets, leaseholds and nonconsolidated
equity investments.
●
The potential for insufficient liquidity
or other factors, such as those described
herein, that could impact
our ability to repurchase shares and
declare and pay dividends, whether fixed
or variable.
●
Potential failures or delays
in achieving expected reserve or production
levels from existing and future oil
and gas developments, including due to
operating hazards, drilling risks
and the inherent uncertainties in
predicting reserves and reservoir performance.
●
Reductions in reserves replacement rates,
whether as a result of the significant declines in commodity
prices or otherwise.
●
Unsuccessful exploratory drilling
activities or the inability to obtain access to exploratory
acreage.
●
Unexpected changes in costs or technical
requirements for constructing,
modifying or operating E&P
facilities.
●
Legislative and regulatory initiatives
addressing environmental concerns,
including initiatives addressing
the impact of global climate change or further regulating
hydraulic fracturing, methane
emissions, flaring
or water disposal.
●
Lack of, or disruptions
in, adequate and reliable transportation
for our crude oil, bitumen, natural gas,
LNG and NGLs.
●
Inability to timely obtain or maintain
permits, including those necessary for construction, drilling
and/or
development, or inability to make
capital expenditures required
to maintain compliance with any
necessary permits or applicable laws or regulations.
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2021 10-K
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●
Failure to complete definitive
agreements and feasibility studies
for,
and to complete construction of,
announced and future E&P and LNG development in a timely
manner (if at all) or on budget.
●
Potential disruption or interruption
of our operations due to accidents, extraordinary
weather events,
supply chain disruptions, civil unrest, political
events, war,
terrorism, cyber attacks, and
information
technology failures, constraints
or disruptions.
●
Changes in international monetary
conditions and foreign currency exchange
rate fluctuations.
●
Changes in international trade relationships,
including the imposition of trade restrictions or
tariffs
relating to crude oil, bitumen, natural
gas, LNG, NGLs and any materials or products
(such as aluminum
and steel) used in the operation of our business.
●
Substantial investment
in and development use of, competing
or alternative energy sources, including
as
a result of existing or future environmental
rules and regulations.
●
Liability for remedial actions, including removal
and reclamation obligations,
under existing and future
environmental regulations
and litigation.
●
Significant operational or investment
changes imposed by existing or future
environmental statutes
and
regulations, including international
agreements and national or regional legislation
and regulatory
measures to limit or reduce GHG emissions.
●
Liability resulting from litigation,
including litigation directly or indirectly
related to the transaction
with
Concho Resources Inc., or our failure
to comply with applicable laws and regulations.
●
General domestic and international
economic and political developments, including armed
hostilities;
expropriation of assets; changes in governmental
policies relating to crude oil, bitumen, natural
gas, LNG
and NGLs pricing; regulation or taxation;
and other political, economic or diplomatic developments.
●
Volatility in the commodity futures
markets.
●
Changes in tax and other laws, regulations
(including alternative energy mandates),
or royalty rules
applicable to our business.
●
Competition and consolidation in the oil and gas
E&P industry.
●
Any limitations on our access to capital
or increase in our cost of capital, including
as a result of illiquidity
or uncertainty in domestic or international
financial markets or investment
sentiment.
●
Our inability to execute, or delays
in the completion, of any asset dispositions or acquisitions
we elect to
pursue.
●
Potential failure to obtain,
or delays in obtaining, any necessary
regulatory approvals for
pending or
future asset dispositions or acquisitions, or that such
approvals may require modification
to the terms of
the transactions or the operation
of our remaining business.
●
Potential disruption of our operations
as a result of pending or future asset dispositions or acquisitions,
including the diversion of management time and
attention.
●
Our inability to deploy the net proceeds from any
asset dispositions that are pending or that we elect
to
undertake in the future in the manner
and timeframe we currently
anticipate, if at all.
●
The operation and financing of our joint ventures.
●
The ability of our customers and other contractual
counterparties to satisfy their obligations
to us,
including our ability to collect payments
when due from the government of Venezuela
or PDVSA.
●
Our inability to realize anticipated
cost savings and capital expenditure
reductions.
●
The inadequacy of storage capacity
for our products, and ensuing curtailments,
whether voluntary or
involuntary,
required to mitigate this physical
constraint.
●
The risk that we will be unable to retain
and hire key personnel.
●
Unanticipated integration
issues relating to the acquisition of assets from
Shell, such as potential
disruptions of our ongoing business and higher than anticipated
integration costs.
●
Uncertainty as to the long-term value of our
common stock.
●
The diversion of management time on integration
-related matters.
●
The factors generally described
in
Item 1A—Risk Factors
in this 2021 Annual Report on Form 10-K and any
additional risks described in our other filings with the SEC.
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71
ConocoPhillips
2021 10-K