b
p
A
n
n
u
a
l
R
e
p
o
r
t
a
n
d
F
o
r
m
2
0
-
F
2
0
2
0
from IOC to
IEC
bp Annual Report and Form 20-F 2020
We have set our strategy to transform from
an International Oil Company to an Integrated
Energy Company focused on delivering
solutions for customers.
This is a major, necessary step in support of our purpose to reimagine
energy for people and our planet, and our ambition to become a net zero
company by 2050 or sooner and help the world get to net zero.
After more than a century defined by oil and gas through two core
businesses, upstream and downstream, we set our strategy to
become a very different energy company in the next decade.
This means we plan to
Significantly scale-up our
low carbon energy business
Transform our customer mobility
and convenience offer
Focus our oil, gas and
refining portfolio
Drive down emissions as
part of our net zero ambition
We remain committed to delivering long-term value
for stakeholders – including shareholders – through
a compelling investor proposition.
As we reinvent bp, we remain committed to performing
while we transform, maintaining our focus on safety,
operational excellence and financial discipline.
About bp
Through our scale, reach and range of activities we deliver heat,
light and mobility products and services to customers around
the world, and we plan to do so increasingly, in ways that we
believe will help drive the transition to a lower carbon future.
We have operations in Europe, North and South America,
Australasia, Asia and Africa.
˜7%
upstream unit
production costs«
reduction
2020 in numbers
$20.3bn
$5.7bn
loss for the year attributable
to bp shareholders
underlying replacement
cost loss«
94%
96%
upstream plant reliability«
refining availability«
$12.2bn
$5.5bn
operating cash flow«
divestment proceeds«
$72.7bn
finance debt
$38.9bn
net debt«
2.4mmboe/d
1,900
upstream production
excluding Rosneft
strategic
convenience sites«
14.1GW
total developed renewables
to FID« and renewables
pipeline« bp net
9%
reduction in estimated
emissions from the carbon
in our Upstream oil and
gas production«
Our quick read
provides a concise summary of
the annual report, highlighting
strategy, performance and
sustainability information.
Our reporting centre
brings together all our
key reports, including
our sustainability report
and energy outlook.
Glossary
Like any industry, ours has
its own unique language.
For that reason, words and
terms marked with « are
defined in the glossary.
bp.com/annualreport
bp.com/reportingcentre
See page 341
Strategic report
Strategic report
Our purpose: reimagining energy
Chairman’s letter
Chief executive officer’s letter
Energy markets
Reinventing bp: Our strategy
Our business model
Our strategic focus areas
Our financial frame and investor proposition
Pursuing a strategy that is consistent
with the Paris goals
Our organizational model
Our financial reporting segments
Key performance indicators
Group performance
Sustainability
Section 172 statement
How we manage risk
Risk factors
Corporate governance
Introduction from the chairman
Board of directors
Leadership team
Board activities
Decision making by the board
How the board has engaged with shareholders,
the workforce and other stakeholders
Governance framework
Learning, development and induction
Board evaluation
People and governance committee
Audit committee
Safety and sustainability committee
Geopolitical committee
Directors’ remuneration report
Remuneration committee
Directors’ statements
Financial statements
Consolidated financial statements of the bp group
Notes on the financial statements
Supplementary information on
oil and natural gas (unaudited)
Parent company financial statements of BP p.l.c.
2
4
6
8
15
16
18
22
26
36
38
39
42
48
63
64
67
72
74
78
80
82
86
88
90
91
92
94
100
102
103
105
127
129
160
231
259
301
Additional disclosures
331
Shareholder information
Glossary
341
Non-GAAP measures reconciliations 348
350
Signatures
351
Cross-reference to Form 20-F
352
Information about this report
352
Exhibits
bp Annual Report and Form 20-F 2020
01
Our ambition is to be a net zero company by 2050
or sooner and to help the world get to net zero.
We’ve set out 10 net zero aims, five to help bp get
to net zero and five to help the world get there too.
Five aims to get
bp to net zero
Five aims to help the
world get to net zero
Our purpose
for people
and our planet.
We want to help the world
reach net zero and improve
people’s lives.
We will aim to dramatically reduce carbon in our
operations and in our production, and grow new
low carbon businesses, products and services.
We will advocate for fundamental and rapid progress
towards the Paris climate goals and aim to be an
industry leader in the transparency of our reporting.
We know we don’t have all the answers and will
listen and work with others.
We want to be an energy company with purpose;
one that is trusted by society, valued by shareholders
and motivating for everyone who works at bp.
We believe we have the experience and expertise,
the relationships and the reach, the skill and the
will to do this.
02
bp Annual Report and Form 20-F 2020
Strategic report
Our strategy is to become an Integrated Energy
Company focused on delivering solutions for
customers. We expect to be a very different
bp by 2030 by implementing this strategy.
To deliver our strategy
we must operate within
a resilient financial frame.
We believe our strategy
and financial frame
support the delivery of
our investor proposition.
Strategic frame
Financial frame
Investor proposition
Low carbon
electricity
and energy
Convenience
and mobility
Resilient
and focused
hydrocarbons
Integrating energy systems
Partnering with countries, cities and industries
Driving digital and innovation
See page 15 for more information on our strategy.
A sustainability frame linking our purpose and
Our sustainability frame
The sustainability frame we set out in September
2020 links our strategy to our purpose – to reimagine
energy for people and planet. It focuses on three
areas: net zero, people and planet.
See page 48 for more information on our sustainability frame.
A coherent approach
to capital allocation
1
Resilient dividend
2
Strong balance
sheet
3
Investing at scale in
the energy transition
4
Investing to maximize
value in resilient hydrocarbons
5
Share buyback
commitment
See page 22 for
more information on
our financial frame.
Committed distributions
Profitable growth
Sustainable value
See page 23 for
more information on
our investor proposition.
E n g a g i n g stakeholders
Our
values and
foundations
E
mbedding int o o u r
D N A
bp Annual Report and Form 20-F 2020
03
Chairman’s letter
While this is a journey that will
require patience, our goal is
that bp over time will become
a more valuable company for
its shareholders and bring
wider benefits for society.
7.9%
annual
dividend yield«
ordinary share
(2019 6.9%)
$6.4bn
total dividends
distributed to
bp shareholders
(2019 $8.3bn)
04
bp Annual Report and Form 20-F 2020
Dear fellow shareholders,
2020: the year of the pandemic
In every sense, 2020 was an extraordinary
year. The worst pandemic in a century has cost
well over 2 million lives and caused worldwide
economic and social disruption. While vaccination
programmes are now building momentum, the
path to recovery remains uncertain.
Because demand for energy is closely linked to
human activity, our sector was deeply affected.
The combination of a steep fall in share values
for almost all oil and gas companies and a new
bp distribution policy significantly affected your
shareholder returns.
As chairman of your board, I am conscious of
my responsibilities to bp’s shareholders. When
the board decided to reset our distribution policy,
it did so with a view to your long-term interests.
Our priorities were, and remain, weathering the
immediate challenge of the pandemic; paying
a resilient dividend; strengthening our balance
sheet; investing into the energy transition;
investing in our resilient hydrocarbons business
and, after that, returning surplus cash« to
shareholders through buybacks.
The board was unanimous in its support for
this course of action, which will help establish
bp as an Integrated Energy Company. I hope
that bp’s new investor proposition and financial
frame give reasons for optimism about bp’s
long-term prospects. As we turn to 2021, the
board’s focus is on supporting bp’s leadership
team to deliver our new strategy, and on
building renewed shareholder confidence
through strategic progress and operational
and financial performance.
2020 was also tough for our people. My board
colleagues and I are proud of them. Their
commitment – on rigs, in refineries, across retail
stations and everywhere else in bp – helped keep
the world’s lights on and allowed us to provide
many emergency services with free or heavily
discounted fuel. Despite new COVID-19-related
practical challenges, our people maintained the
safety of bp’s operations. That is a testament to
their careful work.
bp’s new purpose
2020 was a remarkable year for bp for other
reasons too. With the backing of the board, our
new CEO, Bernard Looney, introduced a new
company purpose: reimagining energy for people
and our planet. That purpose – together with our
strong culture and values – underpins the net zero
ambition that we set out last year, together with
our new strategy, financial frame and investor
proposition. It also informed bp’s reinvention
– the selection of a new leadership team, and
the replacement of bp’s upstream/downstream
model with a new, integrated group structure.
Change of this scale necessitated a
reorganization of how we work. That
reorganization will ultimately see close to
10,000 colleagues leaving bp. Saying goodbye
has been difficult, but the result is a leaner,
flatter, nimbler company – better able to realize
the opportunities of the energy transition.
Macro-economic developments have only
strengthened the board’s belief that the direction
in which we are taking bp is the right one –
including China’s new net zero target, the EU’s
Green Deal, the UK’s plan for a green industrial
revolution, and the US’s recommitment to the
Paris Agreement. Today, global energy markets
are even further down the path of fundamental
change – and bp is well-positioned to help to
speed the world’s journey to net zero.
A year of engagement
While this is a journey that will require patience,
our goal is that bp over time will become a more
valuable company for its shareholders and bring
wider benefits for society. Of course, the journey
to net zero is, in part, one of discovery. For that
reason, the board and bp’s leadership team
know that we must be fully open to advice,
learning and challenge.
2020 was therefore a year of engagement with
our stakeholders, and I am grateful for the inputs
we received – which helped us shape our new
strategy, financial frame and investor proposition,
sustainability frame and position on biodiversity.
We will keep listening, and we count on you to
share your feedback with us as we travel the
road to net zero together.
Strategic report
Evolution of the board
As the company evolves, the board’s
composition will evolve too – reflecting the need
for new experiences and skills aligned with bp’s
new direction. During the year, the board said
goodbye to our former CEO, Bob Dudley, and to
Brian Gilvary, our former CFO. Sir Ian Davis, Nils
Andersen and Dame Alison Carnwath have also
stepped down from the board, and we shall
shortly say farewell to Brendan Nelson.
Collectively and individually they served with
distinction – bp is very fortunate to have had their
wise advice and strong leadership. We are just as
fortunate to welcome Tushar Morzaria, Karen
Richardson and Johannes Teyssen to bp’s board
for the first time.
Closing thanks
I would like to thank Bernard Looney, his
leadership team and everyone in bp for their
work during 2020. Throughout this challenging
year, they showed characteristic determination.
Finally, I thank you, our shareholders. I am
grateful both for the continued support we
received during 2020, and also for the support
of our new shareholders. During 2020, we
received investment and other endorsement
from those who told us they would not have
considered supporting bp were it not for the
transformation we have begun. We look forward
to repaying the faith you have placed in bp.
Helge Lund,
Chairman
22 March 2021
bp Annual Report and Form 20-F 2020
05
Chief executive officer’s letter
06
bp Annual Report and Form 20-F 2020
I want to pay particular tribute
to those on the frontline of our
business who have kept our
plants and platforms running,
our shops and forecourts
open, and energy flowing
to the world.
Dear shareholders,
The year 2020 will be remembered above all
for the pain, sadness and loss of life caused by
COVID-19. At bp, our thoughts are with the
families and loved ones of the colleagues we
have lost. Thousands more on our teams have
had the virus, and life under lockdown has meant
additional challenges, and anxiety for everyone.
I want to pay particular tribute to those on the
frontline of our business who have kept our plants
and platforms running, our shops and forecourts
open, and energy flowing to the world. They
have sacrificed so much and earned our deepest
respect and appreciation.
Responding to brutal conditions
We began our transformation from an
International Oil Company to an Integrated
Energy Company against this backdrop, along
with lower oil and gas prices, lower refining
margins and unprecedented falls in demand for
our retail and aviation fuels. Our response
included lowering costs, strengthening the
balance sheet with an innovative hybrid bond
issue, and advancing our strategy to become
$20.3bn
loss attributable
to bp shareholders
a more diversified, resilient and lower carbon
company. As part of our strategy planning
process, we reviewed our portfolio and
development plans. This work – informed by
bp’s views of the long-term price environment
– led to significant impairment charges and
non-cash exploration write-offs in the
second quarter.
For shareholders, all this was reflected in a reset
dividend and a diminished share price. I recognize
the financial impact this must have had on you.
However, I wholeheartedly believe we will not
just restore, but will enhance the long-term
sustainable value of your company through
the actions we are taking to reinvent bp. And
despite the most brutal operating conditions
I can remember in almost 30 years in this
industry, we have made considerable
operational and strategic progress.
Performing while transforming
The loss of $20.3 billion we reported for the
year is clearly disappointing. However, it in no
way reflects the heroic efforts of the bp team in
extremely difficult circumstances, or their deep
commitment to performing while transforming:
Most importantly – our safety performance
continued to improve.
Reliability of 94% for bp’s operated plants«
and refining availability« of 96% represents
remarkably strong performance, especially
given the challenges faced by our
frontline staff.
Capital was reset and we delivered at the
lower end of the range.
We made good progress towards our net
debt« target, including the contribution from
high grading our portfolio and $6.6 billion of
divestment and other proceeds received
during the year.
New oil and gas production came on from
four major projects« – in India, Oman, the
UK and the US.
Natural gas from the Shah Deniz field in
the Caspian Sea arrived in Italy following
final completion of the historic Southern
Gas Corridor project.
And we doubled our retail network in growth
markets to around 2,700 retail sites«,
plus the addition of around 300 strategic
convenience sites«.
Reinventing bp
This performance is even more remarkable given
that we have been carrying out the most
extensive reorganization in bp’s 112-year history.
We have retired the upstream/downstream
business model that has served bp very well.
In its place we have introduced a leaner, flatter
structure, stripping away tiers of management
and lowering the workforce towards a target of
around 10,000 fewer jobs. My role is now five
layers at most away from more than half of our
employees. That means people’s ideas and
voices can be more easily heard – and decisions
taken much faster.
We are now more centralized, more agile, and
better integrated. This enables us to maximize
value creation in a rapidly evolving market through
economies of scale, and by exploiting synergies
and driving continuous improvement in
operational performance.
We are now organized around four business groups.
Production & operations is the operating heart
of the company – and is focusing our resilient
hydrocarbons portfolio on value.
Customers & products is growing our
convenience and mobility offers for an
increasing number of customers.
Gas & low carbon energy is growing to help
meet rapidly increasing clean energy demand.
Innovation & engineering acts as a catalyst,
opening up new and disruptive business
models and driving our digital transformation.
And our trading & shipping business and
regions, cities & solutions team knit together
the offers of our four core groups to drive
greater value creation.
Reimagining energy
Completing our transformation to a net zero
Integrated Energy Company will take time. But
we are led by our purpose – to reimagine energy
for people and our planet – and motivated by the
opportunity we see in the energy transition.
Trillions of dollars of investment will be needed
over the next 30 years in replumbing and rewiring
the global energy system.
We now have offshore wind partnerships in
the US with Equinor and in the UK with EnBW
– two of the best regions globally for the world’s
fastest-growing source of energy. Our solar
development joint venture«, Lightsource bp, is
growing prolifically. We are working with Ørsted
to develop green hydrogen for our Lingen
refinery. We have joined forces with the mobility
Strategic report
platform DiDi to build a network of electric
vehicle chargers in China, by far the world’s
biggest market for EVs. And we have a growing
list of low carbon partnerships with cities such as
Aberdeen and Houston and some of the world’s
leading companies, including Amazon, Microsoft,
Qantas and Uber.
A compelling investor proposition
We are fully focused at all times on the bottom
line of the business – on executing our strategy
while operating safely, reliably and with discipline.
We continue to build resilience and strength in
the balance sheet as conditions remain
challenging and uncertain while vaccines roll out,
the pandemic recedes, and economies look to
recover. At the same time, we are transforming
to create value from the energy transition over
the long term.
We see tremendous business opportunity in
providing people with the reliable, affordable,
clean energy they want and need. Our net
zero ambition is clearly the right thing for society,
but we know it does not give us a free pass in a
fast-changing world. We have to show you the
evidence that we can compete fiercely and add
value – in service of the compelling investor
proposition we believe we offer:
Committed distributions – including the
dividend as the number one priority;
Profitable growth; and
Sustainable value.
This is all in service of growing long-term
shareholder value, that is our job. And I promise
to keep you well informed as we execute our
plans. As ever, thank you for your continued
support – I will never take that for granted. And
I look forward to any feedback you might have.
Thank you.
Bernard Looney,
Chief executive officer
22 March 2021
bp Annual Report and Form 20-F 2020
07
Energy markets
Global context
The business environment is fundamentally changing. The world is on an unsustainable path
and its carbon budget is running out. Energy markets have begun a process of significant,
lasting change in response to this – shifting increasingly towards low carbon and renewables.
And in 2020 we saw further changes, as COVID-19 spread across the globe.
COVID-19
The COVID-19 pandemic has affected individuals,
countries and businesses. The spread of the
pandemic quickly plunged the world economy
into recession and reshaped social norms
and attitudes.
Globally, businesses have had to change
established assumptions and introduce new
models and ways of working. For bp, it has had
an adverse impact on our business, including on
the demand for our products and on their prices.
But the more we understand about the
consequences for the global economy – and
the inevitable uncertainty it brings – the more
convinced we are that our ambition and strategy
are taking us in the right direction for bp, for our
employees, our shareholders and society.
Impact on the economy
The global economy is estimated to have
contracted 4.3% in 2020, the steepest decline
in economic activity since 1946, caused
by COVID-19.
In advanced economies the recovery from the
initial contraction was dampened by resurgences
of COVID-19 cases, leading to an annual
contraction of 5.4%. Most emerging markets,
excluding China, also experienced deep
recessions, with growth of -5% in 2020,
while in China the economy grew by 2%a.
a World Bank Global Economic Prospects, January 2021.
Our response
As COVID-19 continues to affect communities
around the world, we have focused our effort
on three priorities.
1 Protecting our people.
2 Supporting communities
where we live and work.
3 Strengthening our finances.
Our leadership teams were in daily discussions
to respond to the conditions in the countries
where we operate as the pandemic unfolded.
We had a three-tier response model with
executive-level, business, country and incident
management steering committees. Some
examples are given on the next page.
Mobilizing safely in the North Sea
In 2020 bp managed more
than 15,000 journeys by people
mobilizing to and from our North
Sea assets. As the COVID-19
pandemic took hold in the UK,
the bp North Sea team quickly
implemented wide-ranging
and robust COVID-19-specific
measures to protect the safety and
wellbeing of offshore colleagues.
The ‘Safe Passage’ programme
was introduced during the first UK
lockdown to help individuals travel
to Aberdeen for mobilization as
safely as possible. The programme
provided door-to-door transport,
accommodation during the journey
to Aberdeen and hotels in the
city dedicated to bp staff
and contractors.
We introduced pre-mobilization
COVID-19 testing in Aberdeen,
one of the first operators in the
North Sea to do this. Social
distancing and enhanced hygiene
and cleaning regimes continue
to play a vital role in protecting
the health and wellbeing of our
offshore teams.
Specialist ‘C-MED’ medevac
helicopters, equipped with
an on-board medic and configured
to enable social distancing,
were introduced to safely
transport individuals suspected
of contracting the virus back
to shore for further treatment
and support.
08
bp Annual Report and Form 20-F 2020
1
Protecting our people
Our first priority is the safety and health
of our people.
Our people involved in, or supporting, critical
operations continued at their normal workplace
during the pandemic and we put additional
processes in place to help protect them. These
included operating robust protocols for health
and pre-mobilization checks, PPE, travel and
workplace access, social distancing and isolation.
Employees who were able to work from home
were asked not to come into their workplace
and we put business travel restrictions in place.
Many office-based workers continue to work
from home at the time of publication and are
likely to do so for the foreseeable future as
ways of working change.
We liaised closely with industry peers and
other organizations to regularly test our approach
on specific safety issues. And we created a
global COVID-19 OneMap, providing our
businesses with current local COVID-19 risk
profiles including rates of infection, vaccines
rates and procurement.
2
Supporting communities
Providing essential support for the communities
where our people live and our businesses operate
was a priority throughout our response to
COVID-19. We offered support to governments
and partners, using our expertise and resources
to support the relief effort. The bp Foundation
donated $2 million to the World Health
Organization’s COVID-19 Solidarity Response
Fund, which supports medical professionals and
patients worldwide by providing critical aid and
supplies. The fund also helps track and understand
the spread of COVID-19 and supports efforts
to develop tests, treatments and vaccines.
3
Strengthening our finances
The economic consequences of COVID-19 for
the world remain uncertain at the time of
publication. In response to this uncertainty, we
took deliberate steps to strengthen our finances
– reinforcing liquidity, rapidly reducing spending
and costs, driving our cash balance point lower.
Divestment programme
We delivered our plans for $15 billion of
announced divestments, which commenced
at the start of 2019, in June 2020 – a year
earlier than expected.
Supplying free fuel
for emergency
services vehicles
In 2020 we supplied more than 10 million
litres of free fuel to emergency service
vehicles across the UK.
We ran programmes during 2020 and 2021
offering free fuel to UK emergency vehicles
– including police, fire, blood transportation,
emergency NHS ambulances and NHS
Trust non-emergency vehicles.
Under the programmes, emergency
services vehicles issued with either a bp Plus
or Allstar fuel card could fill up without charge
at bp’s network of 1,200 retail sites across the
UK, including charging of electric vehicles
through bp pulse.
In 2020 we set a new target of $25 billion of
proceeds between the second half of 2020
and 2025, of which we’ve completed or agreed
transactions for over half of this target. This
includes the agreed sale of a 20% interest in
Oman’s Block 61 and proceeds from the
divestments of our petrochemicals business
and Alaska interests.
We have a deep hopper of potential future
divestment options. As we execute this
programme, we will continue to be focused
on value.
Capital expenditure
Capital expenditure« for 2020 was $14 billion,
around 28% lower than 2019. Organic capital
expenditure« for 2020 was $12 billion, in line
with the guidance given in April.
Liquidity
Finance debt was $72.7 billion and net debt«
was $38.9 billion at the end of 2020. We are
actively managing the profile of our debt
portfolio. We issued perpetual hybrid bonds
with a US dollar equivalent value of $11.9 billion
in June 2020, and we bought back an
aggregate US dollar equivalent value of
$8 billion of debt in the third quarter of 2020,
January 2021 and March 2021. bp had around
$44 billion of liquidity, consisting of cash and
cash equivalents (net of restricted cash) plus
undrawn revolving credit facilities committed
credit and bank facilities, at the end of 2020.
In April 2020 Moody’s reaffirmed BP p.l.c.’s
A1 credit rating and revised its outlook from
stable to negative. The short-term P-1 rating
was also reaffirmed.
Strategic report
In January 2021 S&P revised its outlook on
BP p.l.c. from stable to negative and affirmed
BP p.l.c.’s long- and short-term corporate credit
rating of A-/A-2.
From January 2021, Fitch Ratings has provided
a solicited long-term corporate credit rating to
BP p.l.c. of A with stable outlook. In February
2021, Fitch Ratings assigned BP p.l.c. a
short-term corporate credit rating of F1.
bp’s financial performance, including cash flows
and net debt, has been and will continue to be
impacted by the extent and duration of the
current market conditions and the effectiveness
of the actions that it and others take, including
its financial interventions. It is difficult to predict
when current supply and demand imbalances
will be resolved and what the ultimate impact
of COVID-19 will be.
See page 22 for more information
on capital allocation.
We have addressed our response to COVID-19
in further detail throughout this report:
See page 63 Our stakeholders.
See page 64 How we manage risk.
See page 67 Risk factors.
See page 87 Workforce engagement.
bp Annual Report and Form 20-F 2020
09
Energy markets continued
Energy economics
Oil
The COVID-19 pandemic resulted in a sharp
contraction in oil sector demand and production
in 2020.
Global oil consumptiona decreased by
8.8mmb/d to 91.2mmb/d for the year (-8.8%) as
global lockdown measures reduced mobility and
took a toll on economic activity.
On the supply side, unprecedented co-ordinated
output cuts from OPEC+, coupled with curtailed
non-OPEC supply, reduced global oil productiona
by 6.6mmb/d to 93.9mmb/d.
Dated Brent« prices averaged $41.84/bbl in
2020 – a 35% decrease from 2019 levels and
almost 26% below the 2016-18 average.
Prices fluctuated during 2020, reaching a peak
of almost $70/bbl in January on OPEC+ supply
restraints and the decline in Libyan output. Prices
hit a low of almost $13/bbl in April as lockdown
measures were put in place globally. In the
second half of the year prices hovered around
the $40-45/bbl range, before hitting $50/bbl
in December.
Urals prices in North West Europe (Rotterdam)
averaged $41.71/bbl in 2020. The discount
to dated Brent was $0.13/bbl below 2019
($1.25/bbl).
8.8%
decrease in global oil
consumption in 2020
Natural gas
Gas spot prices dropped in all three key regional
markets in 2020.
Refining marker margin
We track the refining margin environment using
a global refining marker margin« (RMM)c.
Henry Hub« prices decreased to $2.08/
mmBtu in 2020 from $2.63/mmBtu in 2019.
US gas prices varied substantially during 2020,
dropping in the second quarter of 2020 due to
the impact of the lockdown, before recovering
in the fourth quarter as production declined
due to the earlier oil price drop and lower oil
and gas drilling activityb.
The UK National Balancing Point« hub price
also dropped significantly from 34.70 pence
per therm in 2019, down to 24.93 pence per
therm in 2020, due to a combination of a mild
winter 2019/20, global LNG oversupply,
demand drop and record-high storage levelsb.
Asian spot prices declined from $5.49/mmBtu
in 2019, down to $4.39/mmBtu on the back of
global LNG oversupply and LNG supply
capacity growth, especially in the USc. They
recovered in the fourth quarter on the back
of strong Asian LNG demand and LNG
supply issues.
Global gas demand dropped by an estimated
2.5% in 2020, while China’s gas demand
continued to grow. Meanwhile, LNG trade
increased modestly during 2020b.
2.5%
estimated decrease in global
gas demand in 2020
COVID-19 significantly impacted the downstream
sector during 2020. Weaker demand drove
product stocks to record highs. OECD
commercial product stocks peaked in August at
over 1,650Mbbls, almost 150Mbbls higher than a
year ago. Since then stocks have declined but are
still above historical levels.
In 2020 COVID-19 impacted demand through
different channels. During the initial global
lockdown period, the drop in demand was
concentrated in road and air travel – hitting
gasoline and jet fuel the hardest. As more
measured domestic social distancing policies
evolved, road mobility and hence gasoline
demand recovered, while jet demand remained
depressed. The broader negative impact on the
economy also dampened diesel demand given
the close link between commercial and industrial
diesel uses and economic activity.
The resulting refining margins have, therefore,
remained extremely weak since the beginning of
the pandemic, with RMM averaging $6.7/bbl in
2020, far lower than the level in 2019 ($13.2/bbl).
Moreover, the weak margin environment
combined with continued capacity additions in
developing markets has prompted a raft of
third-party closure announcements. Some
industry rationalization is expected given the
step change in demand, but this is not likely to be
sufficient to see a sustained rebound in margins
to pre-COVID-19 levels.
$6.7/bbl
global RMM average
in 2020
a IEA Oil Market Report, January 2021©.
b Platts 2020 Review and 2021 Outlook, and IHS Markit: Waterborne LNG Export-Import Data Tables.
c The RMM may not be representative of the margin achieved by bp in any period because of bp’s particular refinery configurations and crude and product slates. In addition, the RMM does not include
estimates of energy or other variable costs.
10
bp Annual Report and Form 20-F 2020
Strategic report
Our Energy Outlook
Our bp Energy Outlook considers three main scenarios that explore the possible pathways
the energy transition may take over the next 30 years. The uncertainty is substantial and
these scenarios are not predictions of what is likely to happen or what bp would like to
happen. Rather they explore the possible implications of different judgements and
assumptions concerning the nature of the energy transition.
Three scenarios to explore the energy transition
Rapid
Net Zero
Business-as-usual
One of many possible scenarios that
can be considered ‘consistent with Paris’,
in line with a ‘well below 2 degrees’
pathwaya. In this scenario emissions from
energy use fall by around 70%, with a fall
of approximately 80% in the developed
world and 65% in the emerging world.
In which global energy systems
emissions fall by 95% by 2050
versus 2018, in line with a ‘1.5 degrees’
pathwaya. Changes in societal
actions and behaviours are a key
driver in this scenario.
A continuation of recent trends without
major change in the pace or direction
of policy tightening; this scenario is not
‘consistent with Paris’ and results in a
reduction in global energy greenhouse
gas emissions of only 10% by 2050
versus 2018.
CO2 emissions from energy use Gt of CO2
40
35
30
25
20
15
10
5
0
-5
1980
1990
2000
2010
2020
2030
2040
2050
History
Rapid
Net Zero
Business-as-usual
IPCC 2 Median
IPCC 1.5 Median
This chart compares the three main scenarios
from the bp Energy Outlook 2020: Rapid, Net
Zero and Business-as-usual, with the range of
scenarios included in the Intergovernmental Panel
on Climate Changeb, which were judged to be
consistent with meeting the Paris climate goalsc.
Well
below
2ºC
1.5ºC
Scenarios for strategic decision making
We have been using scenarios at bp to inform
strategy, manage risk and improve decision
making for many years. The scenarios we used
to inform our new ambition and strategy were
based on a collaborative approach between
our economists, strategists and our senior
management team.
a For more information on Paris-consistent pathways, see page 26.
b The Intergovernmental Panel on Climate Change (IPCC) is the United Nations’ body for assessing the science related to climate change. It is the leading source of data that summarizes the potential
pathways to achieve the Paris goals. The IPCC compiles a database of the published results on mitigation pathways from modelling teams around the world.
c Ranges show 10th and 90th percentiles of IPCC scenarios. See bp Energy Outlook 2020 for more information.
bp Annual Report and Form 20-F 2020
11
Energy markets continued
Some scenarios start from today and project
forward over a timeframe in which the current
structure of the energy system helps to inform
the pace and nature of the transition path. Other
scenarios start in the distant future, breaking free
from the inherent inertia in the energy system
(and potentially our thinking), and look back to the
present from that new perspective. In thinking
about appropriate scenarios to inform our new
strategy, we used both approaches.
The scenarios chosen to explore the range of
uncertainty surrounding the future of the global
energy system span a broad range of energy
transition paths. Importantly, the scenarios are
not predictions of what is likely to happen or
what bp would like to happen. Rather they
consider the possible implications of different
judgements and assumptions and so help to
design a strategy which is resilient to the wide
range of uncertainty we face.
By considering various time horizons, we can
identify key milestones or signposts which might
emerge over the next five, 10 or 30 years and
inform our view of the key sources of uncertainty
affecting the global energy system. We actively
monitor for changes in the external environment,
and refresh or review our scenarios as needed in
response to these signals.
How we create scenarios
We quantify these scenarios in the bp Energy
Outlook 2020 using our global energy modelling
system. This comprises of a suite of models
developed over the past 10 years to help us
understand supply and demand dynamics of
the global energy system.
The modelling framework uses historical data
based on the bp Statistical Review of World
Energy, IEA energy balances and a range of
other energy and non-energy data sets. The
model combines supply, end-use demand,
and production in intermediate sectors,
including power and hydrogen, to create
global energy outlooks.
Each scenario is determined by a set of key
assumptions including population and economic
growth, pace of technological change, resource
constraints and government policies. Prices are
used to balance supply and demand. The
modelling techniques used vary by sector and
include a combination of econometric modelling,
least-cost optimization, adoption curves and
consumer choice modelling. The regional
coverage varies by sector but at its most
aggregated the model produces views for
14 regions, across six sectors, more than 20
energy and technology sources and associated
CO2 emissions from each. It produces annual
data out to 2050.
Scenarios are generated based on our own
judgements alongside views from external
organizations. For example, population growth
from the United Nations, economic growth
supported by views from Oxford Economics,
resource availability based on Rystad Energy’s
global upstream database, power modelling
informed by Aurora Energy Research and global
system dynamics based on a proprietary TIMES
integrated assessment model. All scenarios
typically take into account historical evidence,
current policies, user judgement and
specialist projections.
In developing the scenarios, we benchmark
our views against scenarios from external
organizations including from the
Intergovernmental Panel on Climate Change’s
(IPPC) 2019 Special Report on Global Warming of
1.5°C, IEA’s World Energy Outlook 2020 and IHS
Markit’s Energy and Climate Scenarios.
How scenarios inform our strategy
The scenarios described in the bp Energy Outlook
2020 helped inform bp’s strategy process,
alongside a wide range of other analyses and
information. As we developed the strategy, the
scenarios were reviewed and refined to ensure
they remained relevant, for example, they were
completely refreshed to account for the possible
implications of COVID-19, and they remained
challenging for example, by including a scenario
in which global emissions from energy reach
near zero by 2050.
The aim of the scenarios is to aid our
understanding of how the pace and nature of
the energy transition may affect the global energy
system and so help our strategy be robust and
resilient to the range of uncertainty we face.
Given that, we believe that it is neither useful
nor sensible to try to identify one scenario as
being more or less likely than another.
12
bp Annual Report and Form 20-F 2020
In the bp Energy Outlook 2020, COVID-19 is assumed to have
a persistent impact on economic activity and energy demand.
Strategic report
Global energy demand across the scenarios
Although the three energy outlook scenarios differ in many respects, some trends are common across them and across the wide range of other analyses
and information we refer to. Global energy demand continues to grow, at least for a period, driven by increasing prosperity and living standards in the
emerging world, and there are three common trends in how the structure of energy demand changes over time.
Importance of fossil fuels declines
The share of fossil fuels in global primary energy
falls from around 85% in 2018 to between 65%
and 20% by 2050 in the three scenarios.
World continues to electrify
The rapid growth in renewables is supported by
the increasing role of electricity in total final
energy consumption in the three scenarios.
Rapid growth in renewable energy
Increases in renewable energy dominate growth
in primary energy, with its share increasing from
5% in 2018 to between 20% and 60% by 2050
in the three scenarios.
Shares of primary energy
Shares of total final comsumption
Shares of primary energy
100%
80%
60%
40%
20%
0%
100%
80%
60%
40%
20%
0%
100%
80%
60%
40%
20%
0%
2018
2025
2030
2035
2040
2045
2050
2018
2025
2030
2035
2040
2045
2050
2018
2025
2030
2035
2040
2045
2050
Rapid
Net Zero
Business-as-usual
Rapid
Net Zero
Business-as-usual
Rapid
Net Zero
Business-as-usual
Changing structure of the global energy system
In addition to the changing structure of energy
demand, the scenarios also highlight how global
markets may change if and when there is a
transition to a lower carbon energy system, with
a more diverse energy mix, greater consumer
choice, more localized energy markets, and
increasing levels of integration and competition.
Share of primary energy in Rapid
100%
80%
60%
40%
20%
0%
1900
1915
1930
1945
1960
1975
1990
2005
2020
2035
2050
Oil
Coal
Natural gas
Other non-fossil fuels
Renewables
bp Annual Report and Form 20-F 2020
13
Energy markets continued
Our beliefs on the energy transition
Three features are common across our Energy Outlook scenarios and they
form a set of three core beliefs as to how energy demand is likely to change
over the next three decades.
The world will electrify, with
renewables a clear winner
Customers will redefine
convenience and mobility, driven
by electrification, digital and fleets
Oil and gas challenged but
will remain part of the energy
mix for decades
And those core beliefs lead to three more about how the energy system
will have to change in response to evolving demand, out to 2050.
Energy systems will become
increasingly multi-technology,
integrated and local
Customers – countries, cities,
industries and corporates
– will demand bespoke
energy solutions
Digital will continue to transform
our lives – creating opportunities
to drive innovation, unlock value
and engage new customers
and markets
These core beliefs underpin our new strategy.
bp.com/energyoutlook
14
bp Annual Report and Form 20-F 2020
Reinventing bp: our strategy
Our strategy
An Integrated Energy Company delivering
solutions for customers.
Focuses on three areas of activity: low carbon electricity and energy,
convenience and mobility, and resilient and focused hydrocarbons. Each
focus area represents an attractive opportunity in its own right. Taken
individually, they are not unique to bp. But we plan to leverage three
sources of differentiation to help us amplify value: integrating energy
systems, partnering with countries, cities and industries, and driving
digital and innovation.
Strategic report
From IOC to IEC
We began 2020 operating under our previous
strategy, announced in 2017, which focused
on four strategic priorities:
Growing advantaged oil and gas in the
Upstream.
Market-led growth in the Downstream.
Venturing and low carbon across
multiple fronts.
Modernizing the whole group.
In February 2020, we announced our new
ambition to be a net zero company by 2050 or
sooner and to help the world get to net zero.
And in August we announced a new strategy
to get us there, which builds on the
foundations we’ve developed since 2017.
By following this strategy, we expect bp to be a very different energy company by 2030.
Low carbon
electricity
and energy
Convenience
and mobility
Resilient
and focused
hydrocarbons
Integrating energy systems
Partnering with countries, cities and industries
Driving digital and innovation
Our strategy is underpinned by our new sustainability frame
and by advocating for policies that support net zero.
A sustainability frame
linking our purpose and
See page 48 for more about our sustainability frame.
bp Annual Report and Form 20-F 2020
15
Reinventing bp – our business model
Delivering value for bp, our shareholders
and society
Business model inputs
Skills in the world of energy, built
up over more than 110 years.
Understanding of energy markets
and how they move.
Thousands of expert scientists,
engineers and technologists.
People with outstanding capabilities
in trading, shipping, marketing and
innovation.
Strong relationships with leading
companies, universities and
governments.
Thriving energy transition, convenience
and mobility partnerships and
businesses that we are growing
all over the world.
A resilient financial frame and a
disciplined approach to capital allocation.
Strategic activities
Low carbon electricity
and energy
Convenience
and mobility
Through our gas & low carbon
energy business, we aim to
grow scale. Our low carbon
businesses are complemented
by integrated gas, which
has an important role in the
energy transition.
Our customers & products
business group is an integral
part of our growth and returns
strategy. We aim to put
customers at the heart of
everything we do.
How we aim to create value
Growing our renewables
portfolio, including offshore
wind and solar.
Building an integrated low
carbon electricity position
in select developed and
emerging markets.
Growing our integrated
gas position, building on our
high-value equity upstream
gas, our LNG portfolio«
and our marketing capability.
Scaling our bioenergy
business, focusing
on biofuels, biogas
and biopower.
Accelerating to take early
positions in hydrogen
and carbon capture,
use and storage.
Expanding and scaling our
differentiated fuels and
lubricants offers in growth
markets (see page 24),
aiming to help shape these
markets over time to lean
into the transition to low
carbon mobility.
Redefining convenience
through partnerships with
some of the world’s leading
brands and continuing to
develop innovative offers,
making buying our retail
goods and fuels even more
convenient for customers.
Developing next-gen
mobility solutions, including
electrification, sustainable
fuels and hydrogen.
Safety is our core value. It underpins our business
model and permeates everything we do.
See page 59 for our safety performance in 2020.
16
bp Annual Report and Form 20-F 2020
Resilient and focused
hydrocarbons
Through our production &
operations business, we aim
to produce the affordable
hydrocarbon energy and
products the world needs,
and generate cash to fund
our operations and our
transformation to an Integrated
Energy Company.
Always putting safety
first. Aiming to eliminate
life-changing injuries and
the most serious process
safety events.
Reducing emissions, aligned
with our aims, while delivering
the energy the world needs.
Transforming operations and
improving efficiency.
Maintaining a resilient
portfolio through investment
efficiency and high grading.
Flexibly deploying talent
to our most valuable
opportunities and to
solve our biggest issues.
Reinventing our business model
As we transition from an International Oil Company
to an Integrated Energy Company, we are reinventing
our old business model, which comprised three
main activities:
Finding and generating energy.
Refining, manufacturing and marketing.
Delivering products and services.
Sources of differentiation
Integrating energy systems
We are focused on driving integration
in everything we do. Through integration
we bring everything together, to create
end-to-end solutions for our customers.
214TWh
traded electricity
in 2020
Partnering with countries,
cities and industries
By leveraging relationships and building new
partnerships we aim to provide integrated
energy and mobility solutions to help cities
and industries reduce carbon emissions while
creating exciting business opportunities.
10-15
city
partners
aim by
2030
Driving digital and innovation
We innovate with a strong focus on
digital to drive operational efficiencies,
enable our workforce and engage better
with our customers. This includes building
new businesses through bp ventures
and Launchpad.
38
bp ventures and
Launchpad
businesses
in total
Strategic report
Our new business model is more integrated and
faces the energy transition head on. We believe it
can deliver for the changing demands of stakeholders,
with an absolute focus on operational excellence,
so that our businesses are safe, reliable and efficient.
Delivering value
for our stakeholders
Employees
Investors
Society
Suppliers and partners
Customers
Governments and regulators
By delivering value to
our stakeholders we can
achieve our purpose.
for people
and our planet.
See page 36 for details of
our organizational model.
bp Annual Report and Form 20-F 2020
17
Reinventing bp – our strategic focus areas
Strategic focus areas
Metrics
We aim to grow our renewables and bioenergy
businesses, seek early positions in hydrogen and
carbon capture utilization and storage and strengthen
our gas position. These activities form an integrated
low carbon portfolio that will help transform bp as
we transition from an International Oil Company
to an Integrated Energy Company.
See page 20 for an example
of our strategy in action.
In order to advance our purpose and
ambition, we have identified three strategic
focus areas, and we’ve set targets and
aims against these out to 2025 and 2030.
These provide the basis for a common
set of enduring objectives for bp as we
transform the organization consistent
with the long-term energy transition.
Some examples of how we performed
in 2020 are also set out here.
As we deliver our strategy, we will focus on maximizing value
through operational and commercial excellence, see pages
36-38 for more information.
We will continue to focus on customers
and respond to their changing needs. We
aim to redefine convenience and scale up
our differentiated offers in growth markets
and next-gen mobility solutions, including
electrification, sustainable fuels and hydrogen.
Developed renewables to
final investment decision«
Bioenergy production«
LNG portfolio«
Traded electricity«
Customer touchpoints«
Strategic convenience
sitesb«
Retail sites in growth
marketsb«
Castrol sales and other
operating revenues«
Electric vehicle charge
pointsa«
See page 24 for an example
of our strategy in action.
Margin share from convenience
and electrificationb«
Unit production costs«
Upstream productionc
Upstream plant reliability«
Refining throughput
Refining availability«
Our hydrocarbons business is essential to
our transformation to an Integrated Energy
Company. The cash flow from our oil, gas and
refining activities enable our strategy, allowing us
to invest in the energy transition and support our
two growth areas – low carbon electricity and
energy, and convenience and mobility.
See page 34 for an example
of our strategy in action.
18
bp Annual Report and Form 20-F 2020
2020
3.3GW
2019 2.6GW
30Kb/d
2019 23Kb/d
20Mtpa
2019 15Mtpa
214TWh
2019 250TWh
2025
20GW
2030
50GW
50Kb/d
>100Kb/d
25Mtpa
30Mtpa
350TWh
500TWh
11.5 million
2019 >10 million
>15 million
>20 million
1,900
2019 1,600
2,700
2019 1,300
$5.4bn
2019 >$6.5bn
10,100
2019 >7,500
27.6%
2019 ~25%
>2,300
>3,000
7,000
>8,000
~$7.5bn
>$8bn
>25,000
>70,000
~35%
~50%
$6.39/boe
2019 $6.84/boe
~$6/boe
2.4mmboe/d
2019 2.6mmboe/d
~2mmboe/d
~1.5mmboe/d
94%
2019 94.4%
1.6mmb/d
2019 1.7mmb/d
96%
2019 94.9%
96%
>96%
<1.5mmb/d
~1.2mmb/d
96%
>96%
Strategic report
Performing while transforming
bp and Equinor strategic US offshore wind partnership, see page 20.
Partnered with Microsoft to progress our respective sustainability aims,
including plans to supply Microsoft with renewable energy and extend its
cloud-based services within bp.
Lightsource bp, in which we have a 50% share, has more than doubled
its global presence from five to 14 countries and grown its development
pipeline from 1.6GW to 17GW, since joining with bp in 2016.
Formed the Northern Endurance Partnership, with five energy
companies, to develop the offshore infrastructure to transport and store
millions of tonnes of carbon dioxide emissions safely in the UK North Sea.
Partnered with Ørsted and plan to develop an industrial-scale project
to produce hydrogen from water, powered by wind.
Joined with Aberdeen City Council to help achieve its net zero
vision to reduce carbon emissions and become a climate-positive city.
Agreed to extend our relationship with Amazon, to supply additional
renewable energy to power its operations, and Amazon Web Services,
enabling the acceleration of bp’s programme to digitize its infrastructure
and operations.
More than doubled retail sites in growth markets to 2,700.
Added ~300 strategic convenience sites across our retail network,
bringing the total to 1,900.
Announced the start of our new mobility joint venture« in India with
Reliance, Jio-bp, see page 24.
Increased the number of electric vehicle charge points to 10,100 and
began the rollout of ultrafast charging points across the UK and Germany.
Rolled out 1,400 electric vehicle charge points as part of our joint venture
with DiDi in China.
Increased margin share from convenience and electrification to 27.6%.
a Reported to the nearest 100.
b The nearest GAAP measures of the numerator and denominator are RC profit before interest
and tax for Downstream. A reconciliation to GAAP information is provided on page 318.
We’re on track to deliver on our growth target since 2016 of 900mboe/d
from new major projects« by the end of 2021, with 700mboe/d of
production capacity on line by the end of 2020. And we started up
four major projects: Atlantis in the Gulf of Mexico, see page 34, Ghazeer
in Oman, Vorlich in the North Sea, and KG D6 R Cluster in India.
Completed the Southern Gas Corridor pipeline system, with the
Trans Adriatic pipeline beginning gas deliveries.
Tested the green completions concept on our Ghazeer wells, sending
hydrocarbons to a production facility instead of flaring them.
Sold our petrochemicals business to INEOS.
Ceased fuel production at our Kwinana refinery to convert it into
an import terminal.
Agreed to sell a 20% interest in Oman’s Block 61.
c Relative to 2019, we expect our hydrocarbon production to be around 40% lower by 2030
reflecting active management and high-grading of the portfolio, including divestment of
non-core assets. We will not undertake exploration activity in new countries.
bp Annual Report and Form 20-F 2020
19
Reinventing bp – our strategy in action
20
bp Annual Report and Form 20-F 2020
Strategic report
Low carbon electricity and energy
We’re teaming up with Equinor to form a new
strategic partnership to develop offshore wind
projects in the US. We believe we can achieve
more together, working to become leaders in the
fastest-growing renewables sector and helping
the world get to net zero.
Why offshore wind?
Offshore wind is growing at around 20%
a year globally and is recognized as a core
part of reducing global emissions.
This was bp’s first ever offshore wind
venture and marks an important step
in the delivery of our strategy to rapidly
grow our renewable electricity and
energy portfolio.
Building on this progress in 2021, bp
and Energie Baden-Wuerttemberg AG
(EnBW) were selected as the preferred
bidder for two major leases in the UK
Offshore Wind Round 4, marking our
entry into the largest offshore wind
power sector in the world.
Our partnership with Equinor
will play a vital role in allowing
us to deliver our aim of rapidly
scaling up our renewable energy
capacity, and in doing so help
deliver the energy the world
wants and needs.
Dev Sanyal
EVP, gas & low carbon energy
What we’re doing
The partnership includes development
of four assets in two existing offshore
wind leases on the US East Coast. And
we expect to pursue further opportunities
for offshore wind in the US.
We’re investing $1.1 billion for a
50% share in two leases: Empire
Wind and Beacon Wind.
Empire Wind, NY, is expected to
have 2GW generating capacity,
once operational.
Beacon Wind, MA, is expected to
have 2.4GW generating capacity,
once operational.
In January 2021, the Empire Wind 2 and
Beacon Wind 1 projects were selected
to provide New York State with 2.5GW
of power – the biggest US offshore wind
award to date – adding to the existing
commitment to supply 0.8GW.
Why it matters
Our strategy aims to increase our
annual low carbon investment tenfold
by 2030 and rapidly grow our developed
renewable generating capacity.
The partnership will leverage bp’s trading
expertise and onshore wind experience
with Equinor’s sector-leading track record
in offshore wind, and is expected to deliver
value for our shareholders and help the
world transition to low carbon energy.
2 million
Together, these assets
have the potential to
generate power for more
than 2 million US homes.
See pages 24 and 34 for more
examples of our strategy in action.
bp Annual Report and Form 20-F 2020
21
Reinventing bp – our financial frame and investor proposition
Our financial frame
To reinvent bp and deliver our strategy, we must operate within a resilient financial frame, that combines a
strong balance sheet with cash flow generation to support higher investment into transition businesses and
compelling shareholder distributions.
Our new financial frame aims to provide a
stable foundation for bp, strengthening our
balance sheet, and providing a clear approach
to capital allocation. And through our disciplined
approach to investment, we expect to create
the opportunity to significantly increase our
investment in low carbon activities in this decade,
while also operating a high-quality base business.
A coherent approach to capital allocation
1
Resilient dividend
2
Strong balance sheet
3
Investing at scale in
the energy transition
4
Investing to maximize
value in resilient hydrocarbons
5
Share buyback commitment
A clear set of priorities
Resilient dividend: We aim to fund a resilient
dividend intended to remain fixed at 5.25 cents
per ordinary share, per quarter, subject to the
board’s discretion.
Strong balance sheet: In the near term, we
target deleveraging to $35 billion of net debt«
and maintaining a strong investment grade
credit rating thereafter.
22
bp Annual Report and Form 20-F 2020
Investing at scale in the energy transition:
We plan to allocate sufficient capital to advance
our energy transition strategy, with this allocation
intended to rise once our near-term deleveraging
target is achieved.
We have a range of sector-specific internal
rate of return hurdles for transition and low
carbon investments between 10% and 15%.
For renewable power, we look for returns
of at least 8% to 10% levered.
All of this is then optimized to make sure we
are considering a sufficiently broad range of
economic, strategic and sustainability criteria
in the context of risk and enduring sources of
competitive advantage.
Investing to maximize value in resilient
hydrocarbons: We aim to invest appropriately
in our resilient and valuable hydrocarbons
business to generate sustainable cash flow.
We have set stringent hurdle rates for all
final investment decisions. A payback of
less than 10 years for all investments in
upstream oil and refining.
A payback of less than 15 years for
upstream gas.
Share buyback commitment: We are
committing to return at least 60% of surplus
cash« as share buybacks, having reached
$35 billion net debt and subject to maintaining
a strong investment grade credit rating.
Investment in non-oil and gas
As part of our net zero ambition (see page 49),
we aim to increase the proportion of investment
we make into our non-oil and gas businesses. We
plan to increase investment in low carbon from
around $750 million in 2020 to $3-4 billion by
2025 and to around $5 billion a year in 2030.
Our 2020 capital expenditure« against our aim
5 non-oil and gas activities of around $750 million
included a partial acquisition payment for the
US offshore wind partnership with Equinor, see
page 20, our investments in electrification and
advanced mobility, and investment into activities
through bp ventures and Launchpad.
In 2020 Lightsource bp progressed multiple
solar projects, including developments in Texas,
Indiana, Colorado and Spain. bp Bunge now
has capacity for 1.8 billion litres of ethanol
production a year and is able to export over
1,200GWh of electricity to the national grid in
Brazil. We expect overall low carbon spend to
grow significantly in 2021.
Capital expenditure for convenience and mobility
grew to $2.2 billion in 2020, weighted towards
growth and with a focus on new retail sites«,
differentiated fuels and lubricants and next-gen
mobility. We formed a joint venture with Reliance
in India and plan to scale up to 5,500 retail sites
by 2025, see page 24.
We made significant progress towards our 2030
aim of more than 70,000 electric vehicle charge
points« through the DiDi joint venture in China,
investment in ultra-fast electric vehicle charging
points in Germany, and bp pulse – the UK’s
largest public charging network.
Overall, bp transition and low carbon capital
expenditure in 2020 was around 20% of the
capital mix, and by 2030 we expect it to be as
much as 50% of our capital expenditure, of
which a significant majority will be low carbon.
As a reminder, the CA100+ resolution«
requires us to disclose:
Our anticipated investment in oil and gas
resources and reserves – this is anticipated
to be less in 2021 than it was in 2020.
Our anticipated investment in other energy
sources and technologies, which is
anticipated to be significantly greater than
2020 levels, as described above.
Strategic report
Our investor proposition
We believe that our strategy and financial frame support the delivery of our investor proposition.
Committed
distributions
Profitable
growth
Sustainable
value
through the resilient
dividend and our
commitment to
share buybacks
as measured by
adjusted EBIDA
per share«
and ROACE«
through investment
in a company that
is helping the world
decarbonize
2021 guidance
Upstream reported production excluding Rosneft
Total capital expenditure«
Depreciation, depletion and amortization
Gulf of Mexico oil spill payments (post-tax)
Other businesses and corporate underlying annual charge
Underlying effective tax rate«
a Includes an uplift in valuation of a venture investment of $0.3 billion.
b Nearest equivalent GAAP measure: effective tax rate 17%.
2020 actual
2.4mmboe/d
$14.1bn
$14.9bn
$1.6bn
$1.0bna
-14%b
2021 guidance
Lower than 2020.
Underlying production«
slightly higher than 2020
~$13bn
Similar level to 2020
~$1bn
$1.2-1.4bn
Higher than 40%
bp Annual Report and Form 20-F 2020
23
Reinventing bp – our strategy in action
24
bp Annual Report and Form 20-F 2020
Strategic report
Convenience and mobility
We aim to become a leading player in India’s
fuels and mobility market through our Jio-bp
joint venture with Reliance.
The joint venture« will bring together
Reliance’s market-leading Jio brand
presence with bp’s extensive global
experience in convenience, fuel retailing
and aviation operations. In addition,
Castrol lubricants, India’s number one
premium lubricant brand, will also be
available across the network.
What we’re doing
Operating under the Jio-bp brand, we
expect to grow Reliance’s current fuel
retailing network of more than 1,400
retail sites« to 5,500 by 2025. The joint
venture also plans to increase its aviation
presence from 30 to 45 airports.
Why we’re doing it
India is set to be one of the fastest-
growing fuels and lubricants markets in
the world over the next 20 years, with
the number of passenger cars forecast
to grow nearly six-fold over that period.
We see opportunities over time to
shape low carbon mobility solutions
for customers in India by supporting
the electrification of two and three-
wheel transport and providing battery
management solutions.
What sets us apart
Jio-bp sites will seek to offer Indian
consumers high-quality, differentiated
fuels and tailored convenience services,
benefiting from bp’s global convenience
and mobility experience and Reliance’s
scale, access and digital connection to
millions of customers.
Customers will also have access to
loyalty offers and our Castrol lubricants.
This new venture is a unique
opportunity to build a leading,
fast-growing business that
can help meet India’s demands
and create exciting new digital
and low carbon options
for the future.
Bernard Looney
Chief executive officer
5,500
Jio-bp retail sites
expected by 2025
See pages 20 and 34 for more
examples of our strategy in action.
bp Annual Report and Form 20-F 2020
25
Reinventing bp – consistency with the Paris goals
Pursuing a strategy that is consistent
with the Paris goals
What we mean by Paris consistent
We aim to be recognized as a leader in
transparency for our sector, in the knowledge
that investors and other stakeholders are seeking
to understand whether companies and their
strategies, targets and aims are consistent with
the world meeting the goals of the Paris
Agreement on Climate Changea (the Paris goals).
This is what we refer to as ‘Paris consistency’.
We believe the world is on an unsustainable
path – the carbon budget is running out – and
needs to reach net zero greenhouse gas
emissions. And we believe that there are a
range of global pathways to achieve the Paris
goals, with differing implications for regions,
industries and sectors, so business strategies
need to be flexible.
Our approach to determining Paris consistency
is based on three key principles. We believe
that our strategy satisfies all three principles
and therefore the board considers it to be
consistent with the Paris goals.
1. Informed by Paris-consistent energy
transition scenarios – a company’s strategy
should be informed by Paris-consistent scenarios.
We see the Intergovernmental Panel on Climate
Change (IPCC) as the most authoritative source
of information on the evolving science of climate
change and we use it and other sources to inform
our strategy.
The IPCC highlights that there are a range of
global pathways by which the world can meet
the Paris goals, with differing implications for
regions, industries and sectors. For many years
to come oil and gas features in the energy mix
in the IPCC’s suite of Paris-consistent scenarios,
albeit progressively decarbonized and ultimately
offset; the exact trajectory for oil and for gas
varies from scenario to scenario.
bp’s new strategy is informed by all of these
considerations. It is designed to drive progressive
decarbonization, while remaining flexible and
adaptable to the many different potential
pathways the energy transition may take,
including various Paris-consistent pathways.
26
bp Annual Report and Form 20-F 2020
2. Contributing to net zero – whether a
company’s strategy enables it to make a positive
contribution to the world meeting the Paris goals.
We believe that bp’s strategy enables us to make
just such a contribution. It is designed to deliver
value, while advancing bp towards meeting our
net zero ambition and helping the world get to
net zero too. Together, we believe this sets out
a path that is consistent with the Paris goals.
There are many different ways in which a
company at the heart of the energy sector can
make a meaningful contribution – including action
on greenhouse gas emissions (GHG) measured
by emissions metrics like Scope 1, 2 and 3.
Paris consistency also includes consideration
of a range of other activities, such as technology
development, policy advocacy, low carbon
collaboration and investments in low carbon.
Our strategy seeks to address all of these by
reshaping bp’s business around our three focus
areas and three sources of differentiation,
see page 15.
Some ways of contributing are more readily
measured by quantitative metrics than others
– but all can be important, whether or not they
translate into GHG reductions for the company.
To illustrate this, in terms of low carbon
investment, by 2030 we aim to increase the
amount of renewable energy generating capacity
we have developed to 50GW, as part of our
increased capital expenditure on low carbon
businesses. This aim supports the Paris goals
by increasing the low carbon options available
to energy consumers. However, it does not
reduce our Scope 1, 2 or 3 emissions. And it
may not result in a decrease in the overall
intensity of bp’s marketed products, because
that is dependent on the extent to which we
market the resulting renewable power, which
is a commercial consideration.
Additionally, our strategy is underpinned by
our aim to more actively advocate for policies
that support net zero, including carbon pricing.
Helping policy makers to design and put in place
low carbon policies can help deliver our strategy
and take advantage of the huge opportunities
associated with achieving the Paris goals.
Well-designed low carbon policies can advance
the decarbonization of a whole economy –
something potentially of far greater impact than
anything a single company can achieve through
its own portfolio.
3. Strategic resilience – a Paris-consistent
strategy should position the company for success
and resilience in a Paris-consistent world – a
world that is progressing on one of the many
global trajectories considered to be Paris
consistent, and ultimately meets the Paris goals.
We believe this means having a strategy
that’s flexible enough to manage the inherent
uncertainty in the range of potential global
pathways, including those that can achieve
the Paris goals.
Our new strategy is designed to provide this
flexibility. In setting the strategy, the board and
management referred to the range of scenarios
set out in the bp Energy Outlook 2020, see
page 11. We see huge opportunity in the energy
transition, including the Outlook’s ‘Rapid’ and
‘Net Zero’ scenarios, which we believe are two
of many possible Paris-consistent pathways for
the world. Our strategy also mitigates the risks
associated with a scenario such as the Outlook’s
‘Delayed and Disorderly’ transition.
As a result, our strategy is designed to be
resilient across scenarios, including those that
are Paris consistent, but is weighted towards
a rapid transition.
a Paris Agreement
1 Article 2.1(a) of the Paris Agreement states the goal of ‘Holding the increase in the global average temperature to well below 2°C
above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels, recognizing that
this would significantly reduce the risks and impacts of climate change’.
2 Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, parties aim to reach global
peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country parties,
and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between
anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of
equity, and in the context of sustainable development and efforts to eradicate poverty.
Strategic report
Responding to increased shareholder interest on Paris consistency
In 2019 the board recommended that shareholders support a special resolution requisitioned by Climate Action 100+ (CA100+) on climate change
disclosures. The CA100+ resolution passed with more than 99% of the vote. This is the second year we have included responses throughout the
annual report. We have adopted a similar approach to the bp Annual Report and Form 20-F 2019.
The CA100+ resolution, which includes safeguards such as protections for commercially confidential and competitively sensitive information, is on
page 341. Key terms related to this resolution response are indicated with « and defined in the glossary on page 341. These should be reviewed
with the following information.
Element of the CA100+ resolution
Related content
Where
Strategy that the board considers in good faith to be consistent
with the Paris goals.
How bp evaluates each new material capex investment« for consistency
with the Paris goals and other outcomes relevant to bp strategy.
Disclosure of bp’s principal metrics and relevant targets or goals over
the short, medium and long term, consistent with the Paris goals.
Anticipated levels of investment in:
(i) Oil and gas resources and reserves.
(ii) Other energy sources and technologies.
bp’s targets to promote operational GHG reductions.
Estimated carbon intensity of bp’s energy products and progress over time.
Any linkage between above targets and executive pay remuneration.
Our strategy
Pursuing a strategy that is consistent with the Paris goals
Our investment process
Key performance indicators
Sustainability: net zero targets and aims
See ‘TCFD metrics and targets’ for an overview
Our financial frame
Sustainability: net zero targets and aims
Sustainability: aim 3
Directors’ remuneration report
2020 annual bonus outcome
2021 remuneration policy on page
15
26
29
39
49
55
22
49
50
103
110
124
Portfolio resilience
We are managing our portfolio to be resilient
to the uncertainties surrounding the energy
transition. By 2030 we expect to have a smaller,
more resilient and focused oil and gas portfolio.
This is supported by our evaluation of each new
material capex investment for Paris consistency
and our long-term price assumptions, which were
reviewed in June 2020. We lowered our price
assumptions and extended them to 2050 so that
they are now consistent with our long-term time
planning horizon, see page 28.
We are building a portfolio that is more
robust in a low carbon world. We believe
that the diversification of our portfolio and
decarbonizing our hydrocarbons business
will make bp more resilient to Paris-consistent
pathways. And this will allow us to continue
to redeploy capital to support our strategy to
become an Integrated Energy Company – aiming
to deploy an appropriate mix of cash flow from
hydrocarbons and capital released by
divestments into ambitious plans for growth
in our low carbon, convenience and mobility
businesses, see page 18.
Scale and reach
Our global footprint and interests in multiple
sources of energy provide resilience through
exposure to different price environments, and
our presence in over 70 countries enables access
to new markets. Our track record of creating
mutually beneficial strategic partnerships helps
our resilience, and we are building new and
deeper relationships with governments, cities
and corporate customers at a scale that we
believe is difficult for others to replicate. Our
presence across the energy value chain and
our ability to provide integrated energy solutions
for our customers position us to succeed in a
Paris-consistent world.
Targets and aims
Our strategy is supported by clear business
plans, underpinned by specific short, medium
and long-term targets and aims for 2025, 2030
and 2050 or sooner, including:
Aiming to be net zero across our entire
operations (Scopes 1 and 2).
Aiming for the carbon in our upstream oil
and gas production (Scope 3) to be net zero.
Aiming to cut the life cycle carbon intensity
of our marketed products by 50% (which
includes the associated Scope 3 emissions).
From a 2019 baseline, we aim to increase
our annual low carbon investment ten-fold
to around $5 billion a year, building out an
integrated portfolio of low carbon technologies,
including renewables, bioenergy and early
positions in hydrogen and carbon capture,
use and storage (CCUS).
Over the same period, our oil and gas production
is expected to reduce by at least 1 million barrels
of oil equivalent a day, or 40%, from 2019 levels.
bp Annual Report and Form 20-F 2020
27
Reinventing bp – our investment process
Our investment process
Key investment appraisal assumptions
Brent oil ($/bbl)
Henry Hub gas ($/mmBtu)
RMM«
Carbon price (US$/tCO2e)
Central case real (2020)
2021
50
3.00
10
2025
50
3.00
12
2030
60
3.00
12
2040
60
3.00
10
2050
50
2.75
10
2021
2025
50
50
2030
100
2040
200
2050
250
Impairment testing
As a result of the revision of long-term price assumptions used for investment appraisal, we also
revised the price assumptions we use in value in-use impairment testing. These two price sets
are now aligned.
See pages 166-167 for more about oil and natural gas price assumptions used for
impairment testing and relating sensitivity testing.
Investment process price assumptions
All investments are evaluated against our
long-term price assumptions across a range of
alternative prices (central, upper and lower) for
oil, natural gas and refining margins. In addition,
all investment cases above defined thresholds
for anticipated annual greenhouse gas (GHG)
emissions from operations must estimate
those anticipated GHG emissions and
include an associated carbon price into the
investment economics.
All price assumptions place some weight on
scenarios in which the transition to a low carbon
energy system is sufficiently rapid to meet the
goals of the Paris Agreement, as well as
scenarios in which the transition is not, or may
not be, sufficiently rapid. They also place some
weight on a range of other factors, which can
drive prices, and are not related to the goals
of the Paris Agreement.
These price ranges do not link to specific
scenarios or outcomes, but instead try to
capture the range of different possibilities
surrounding the future path of the global energy
system. The nature of the uncertainty means
that these price ranges inevitably reflect
considerable judgement. The ranges are
reviewed and updated on an annual basis as our
understanding and judgement about the energy
transition evolves.
In addition to consideration of a range of price
assumptions, investment cases are asked to
present scenarios covering a range of variables,
related to the economics of the investment,
such as cost, resource, policy changes and
schedule, to highlight the robustness of
investment cases to a range of other factors.
Price assumptions
Revising long-term price assumptions
Our price assumptions are determined for use
in our investment appraisal processes. They
are also used to inform decisions about internal
planning processes and the impairment testing
of assets for financial reporting.
What the prices are
As part of our strategy development we
reviewed our portfolio and capital development
plans. That work was informed by bp’s views
of the long-term price environment and its
balanced investment criteria. Together these
create a framework that seeks to ensure
investments align with our strategy and add
shareholder value.
Additionally, with the COVID-19 pandemic
continuing throughout 2020, we see it having
an enduring impact on the global economy, with
demand for energy weaker than expected for a
sustained period.
We attach increasing weight to the possibility
that the aftermath of COVID-19 will accelerate
the pace of transition to a lower carbon economy
and energy system, as countries seek to ‘build
back better’ so their economies are more resilient
and sustainable.
As a result of all the above, we revised down
our long-term price assumptions, and also
extended them to 2050 to align with the horizon
of our ambition. The next few years will likely
see periods of market volatility as demand
recovers against a backdrop of reduced levels
of investment and we believe we are well
positioned to benefit from any near-term
increase in oil prices. The role of long-term price
assumptions is to look through this near-term
volatility and help ensure our future projects
are resilient to the longer-term trends affecting
our industry.
Our revised investment appraisal long-term
price assumptions are now an average of
around $55/bbl for Brent« and $2.90 per mmBtu
for Henry Hub« gas (2020 $ real), from 2021-
2050. We consider these lower long-term price
assumptions to be broadly in line with a range
of transition paths consistent with the Paris
goals. However, they do not correspond to
any specific Paris-consistent scenario. We
also revised our carbon prices for the period
to 2050, and these now include a price of
$100/teCO2 in 2030 (2020 $ real).
28
bp Annual Report and Form 20-F 2020
Strategic report
Investment governance and evaluating consistency with the Paris goals
Governance
bp’s investments fall within a governance
framework. This seeks to ensure investments
align with our strategy, fall within our prevailing
financial frame, and add shareholder value.
The governance framework also provides for
investments to be assessed consistently and
against a range of other outcomes relevant to
our strategy, including a range of environmental
and sustainability factors.
Investments follow an integrated stage-gate
process designed to enable us to choose and
develop the most attractive investment cases.
A balanced set of investment criteria is used,
see page 30. This allows for the comparison
and prioritization of investments across an
increasingly diverse range of business models.
The governance framework also specifies that
proposed investments are tested, including
against carbon prices for projected operational
emissions, and are subject to assurance by
functions independent of the business before
a final investment decision (FID) is taken.
See page 88 for more information
on bp’s governance framework.
Resource commitment meeting
For capital investments above defined financial
thresholds for organic or inorganic spend,
the investment approval is conducted by the
executive-level resource commitment meeting
(RCM), which is chaired by the chief executive
officer. The RCM reviews the merits of each
such investment case against a balanced set
of criteria and considers any key issues raised
in the assurance process.
The CA100+ resolution requires bp to disclose
how we evaluate the consistency of new material
capex investments« with (i) the Paris goals and
(ii) a range of other outcomes relevant to bp’s
strategy. bp’s evaluation of consistency of such
investments with the Paris goals was undertaken
by the RCM for new material capex investments
sanctioned in 2020, see page 31. bp’s evaluation
of an investment’s consistency with ‘a range of
other relevant outcomes’ is achieved by
considering its merits against bp’s balanced
investment criteria as described on page 30.
The role of the board
The board assesses the impact of portfolio
changes, such as strategic acquisitions and the
allocation of capital. The board reviews capital
investments that are more than $3 billion for
resilient hydrocarbons, more than $1 billion for
all transition or low carbon investments and, in
addition, any significant inorganic acquisition that
is exceptional or unique in nature.
bp board
Reviews investment cases more than $3 billion for resilient hydrocarbons,
more than $1 billion for all transition or low carbon investments and
any significant inorganic acquisition that is exceptional or unique in nature.
Resource commitment meeting
Approves investment decisions related to existing and new lines of business above
$250 million organic and $25 million inorganic, or which exceeds the relevant EVP financial
authority, and for any project considered strategically important such as new market entry.
Investment allocation committees
EVP level forums to review investment cases within a business group
as per individual EVP financial authority (up to $250 million organic,
$25 million inorganic capital investment).
Business unit investment governance meetings
SVP level forums which review investment cases within a business
group, enabler or integrator up to the individual SVP financial authority.
Cross-group meetings and forums
Meetings and forums to allow cross-group discussions and integration. Includes
Country Forums, Regional Energy Plan Forum, the Carbon Table and Digital Forum.
The forums do not hold decision rights, but inform and underpin the decision-making
process delivering integration opportunities across bp.
bp Annual Report and Form 20-F 2020
29
Reinventing bp – our investment process
Balanced investment
criteria
Six factors
Strategic
alignment
Safety
and risks
Investment
economics
Investment
criteria
Sustainability
Volatility
and
rateability
Optionality
and
integration
Strategic alignment
For all investment cases, we consider whether
the investment supports delivery of our strategy,
see page 18. And if it involves distinctive
capability that bp has, or intends to develop, and
whether it adds to an existing ‘scale’ business
within the portfolio or could help us create one.
Investment economics
We consider investment economics against
a range of measures including internal rate of
return, net present value, discounted payback,
profitability index and investment efficiency,
using a set of scenarios for commodity prices,
margins and carbon prices (where relevant).
Safety and risks
Investment cases are required to describe
risks unique to the project which have a
significantly higher probability than usual or
have a significantly greater impact (relative
to the size of the project) were they to occur.
Sustainability
All investment cases are considered against
appropriate environmental and sustainability
considerations, and sustainability measures,
including carbon. Investment cases above
defined thresholds for anticipated annual
greenhouse gas (GHG) emissions from
operations must estimate those anticipated
GHG emissions and include an associated
carbon price in the investment economics.
Investments are considered against stringent
differentiated hurdle rates.
1. A payback of less than 10 years for all
investments in upstream oil, refining and for
fuels retail in mature markets; together with
an internal rate of return hurdle.
2. A payback of less than 15 years for
upstream gas; together with an internal
rate of return hurdle.
3. We have a range of sector-specific internal rates
of returns of between 10% and 15%. And finally,
for renewable power we look for returns of at least
8% to 10% levered.
Volatility and rateability
Economic metrics are also considered in
the context of the cash flow certainty of
the investment assumptions. For example,
a high-return deepwater tieback will have less
certain and more volatile (oil-price linked) cash
flows than a lower return but more certain
renewable power project with a long-term power
purchase agreement (and a fixed power price).
Optionality and integration
All investment cases are requested to
quantify the strategic optionality that might
be accessed through follow-on activity and
regular cross-entity forums enable integration
opportunities to be identified. For example,
an offshore wind development may provide
additional optionality for power offtake and
integration into our digital platforms.
All group-wide investment cases are required to
set out the investment merits and are considered
against a set of balanced criteria.
This standardized approach creates a level
playing field for decision making and allows
portfolio-wide comparisons of investment cases.
Further, the decision to endorse an investment
based on the information provided represents
bp’s evaluation that the investment is considered
consistent with a range of other outcomes,
relevant to bp’s strategy.
In 2020 the standardized approach for investment
cases was reviewed to place a greater focus on
our strategy, sustainability and integration value.
These changes, and associated nomenclature,
ensure our investment framework is consistent
with our strategy.
When taking investment decisions, we consider
six factors, although our decisions may also take
other factors into account as appropriate.
30
bp Annual Report and Form 20-F 2020
Strategic report
Evaluation process
When evaluating the consistency of our 2020
new material capex investments« with the
Paris goals, a focus of the evaluation criteria
was on their competitiveness and financial
robustness as the prices of different forms of
energy and products adjust in response to the
changing market environment.
For new material capex investment decisions
taken from September 2020, the evaluation used
our revised central price assumptions of around
$55/bbl for Brent« and $2.90 per mmBtu for
Henry Hub« gas (2020 $ real), from 2021-2050.
It also used our revised central carbon price
assumptions, applied to the anticipated
operational greenhouse gas emissions associated
with the investment, for the period to 2050.
These now include a price of $100/teCO2 in
2030 (2020 $ real), see page 28.
Our resource commitment meeting (RCM)
evaluates consistency with the Paris goals
by considering them against a balanced set
of investment criteria, see page 30.
For each of the investment criteria, a
qualitative explanation of each business case
was considered and presented to the RCM
or relevant investment committee, as per the
description on page 29.
Our new material capex investments are intended
to support the delivery of bp’s strategy. In-scope
investments are defined as:
New: investment in a new project or
extension of an existing project/asset,
or share of an entity that is new to bp
or a substantial increase in bp’s share.
Material: more than $250 million
capital investment.
Capital expenditure: includes organic
and inorganic.
2020 was an exceptional year, and one aspect of
bp’s response was to reduce our planned capital
expenditure, see page 9. As a result, there were
only three new material capex investments –
unusually low, and less than half the number in
2019. So bp decided to voluntarily conduct and
disclose Paris-consistency evaluations for the
four largest new capex investments which fell
below our materiality threshold. We do not
expect to disclose such evaluations of non-
material investments in future years. To maintain
consistency of approach, the conduct of these
evaluations was delegated to a subset of
the RCM.
Quantitative evaluations
Two quantitative guide levels were considered
to inform the evaluation of Paris consistency. As
stated in the bp Annual Report and Form 20-F
2019, we continue to develop our approach and
in 2020 we made a number of improvements,
including benchmarking investment economics
against our agreed economic investment
hurdles; evaluating investments on the revised
price assumptions; and setting a lower carbon
intensity guide. As our approach matures with
experience, we may continue to adjust or
supplement these.
Investment economics
The calculation of internal rate of return (IRR)
and discounted payback uses the ‘central-price’
case for commodity prices and margins and the
‘central’ carbon price. Economic indicators are
then benchmarked against the economic hurdles,
see page 30. As a guide, we would normally
target a minimum threshold of greater than
1.0x on this basis.
For clarity, Paris-consistency evaluations for
investment decisions made before September
2020 were measured against the previous
long-term price assumptions and against the
profitability index (PI) measure. For details, see
the bp Annual Report and Form 20-F 2019,
page 22.
Environment and sustainability
Where appropriate, we measure the operational
carbon intensity« of the investment relative to
that of the 2020 portfolio average for the
segment or the related business activity
(upstream, refining, offshore wind). As a guide,
we would normally target a ratio of less than
100%, meaning that the investment is expected
to reduce the average operational carbon
intensity of that portfolio.
The potential impact of new material capex
investments on bp’s greenhouse gas emission
targets is a further consideration.
There may be instances when new material capex investments are evaluated as consistent
with the Paris goals despite either or both of these guide levels not being met.
bp Annual Report and Form 20-F 2020
31
Reinventing bp – our investment process
The respective rankings of investment performance against each of the quantitative
guide levels
Investment economics
Against economic hurdles
Sustainability
Carbon intensity (%)
Guide
Guide
>$250 million
Voluntary disclosures
>$250 million
Voluntary disclosures
1 The 2020 investments have been ranked against the two guides (as applicable to the evaluation of each investment).
As a result, they are ordered differently in each graph above.
2 For one of the investments the operational carbon intensity was not calculated due to the nature of these investments.
The projected operational carbon intensity of renewable power businesses is not considered necessary to quantify for
these purposes as the relevant operational emissions would not be expected to be significant.
Evaluation outcome
As shown in the chart, each of the new
material capex investments approved in 2020
met the evaluation guides, applicable to the
type of investment at the time that the
investment decision was made. Each of these
investments was evaluated to be consistent
with the Paris goals.
Similarly, the four additional (non-material) new
capex investments in 2020, referred to on page
33, also met the evaluation guides, with the
exception of one investment not meeting the
guide level for carbon intensity. This investment
was evaluated to be consistent with the Paris
goals, based on the role liquefied natural gas
(LNG) plays in the energy transition, especially
in the Asia Pacific region in which the project is
located, and the strength of the investment
economics – with a short payback period,
delivering short-cycle cash returns and reducing
the timeframe during which the investment
would be exposed to uncertainties associated
with Paris-consistent pathways.
In addition, when this investment is benchmarked
on the carbon intensity measure against other
LNG projects, instead of the upstream portfolio
average, it benchmarks towards the low end of
the range.
Each of the four additional capex investments
was evaluated to be consistent with the
Paris goals.
32
bp Annual Report and Form 20-F 2020
Strategic report
Decisions taken in 2020
In 2020 three new material capex investment
decisions qualified for evaluation of Paris consistency,
using our materiality threshold of $250 million.
In addition, because there was an unusually low
number of new material capex investments in 2020,
we also decided to evaluate the Paris consistency of
the four largest new capex investments which fell
below our materiality threshold.
Herschel development
Three-well tie-in to the existing
Na Kika infrastructure in the US
Gulf of Mexico.
Lambert Deep GWF-3
Four-well subsea tieback to
the existing Karratha gas plant
in Australia.
Shafag-Asiman
exploration well
Gas exploration well in
the Shafag-Asiman field
in Azerbaijan.
US offshore wind
acquisition
Entry into the US offshore
wind market through a strategic
partnership with Equinor to
develop four assets in existing
wind leases.
Qattameya Shallow
Additional spend to bring
the Qattameya gas field
in Egypt online.
Isabela 3
Single-well tie-in to the
Na Kika platform in the
US Gulf of Mexico.
Galapagos Deep
West well
Exploration well in
‘Cretaceous Thicks’ play
in the US Gulf of Mexico.
bp Annual Report and Form 20-F 2020
33
Reinventing bp – our strategy in action
34
bp Annual Report and Form 20-F 2020
Strategic report
Resilient and focused hydrocarbons
In July 2020, we began production at our major project
Atlantis Phase 3 in the US Gulf of Mexico safely and on
time, despite the challenges of the COVID-19 pandemic.
Since then, we have added a second well and are on
schedule to start a third well by April 2021.
Why it’s important
Atlantis Phase 3 demonstrates our
strategic shift towards resilient and
focused hydrocarbons for value creation.
The project uses world-class existing
infrastructure located in the Atlantis field
to increase production at higher margin.
Drilling completions and offshore
construction were executed with
zero personal injuries.
Harnessing digital and innovation
The team used advanced seismic imaging
expertise to identify the ‘field within
a field’ and designed the new subsea
system to access and deliver these barrels.
What’s involved?
The project includes a subsea
production system for eight new wells
tied into Atlantis, which is designed
to boost the platform’s production.
Building on our track record
The start-up of this project marks
an important milestone for our
resilient and focused hydrocarbons
businesses under our new strategy.
We started up three other major
projects« during 2020: Ghazeer in
Oman, Vorlich in the UK North Sea
and KG D6 R Cluster in India.
We’re on track to deliver on our
target since 2016 of 900mboe/d from
new major projects by the end of
2021, with 700mboe/d of production
capacity online by the end of 2020.
Atlantis Phase 3 is a great
example of how oil and gas
projects support bp’s strategy by
focusing our efforts in the basins
we know best and close to
existing infrastructure.
Starlee Sykes
SVP, Gulf of Mexico and Canada
400,000
hours worked
offshore
Zero
injuries
See pages 20 and 24 for more
examples of our strategy in action.
bp Annual Report and Form 20-F 2020
35
Reinventing bp – our organizational model
To deliver our net zero ambition
and strategy we are reinventing bp
Our organizational model is designed to drive operational excellence and synergies through
common processes and economies of scale. The model consists of four business groups…
Gas & low carbon energy
Brings our energy teams together
to create focused low carbon
energy solutions. It also pursues
the development of decarbonization
technologies and potential moves
into new value chains such as
hydrogen and carbon capture,
use and storage.
Responsible for:
Integrated gas businesses.
Onshore and offshore wind.
bp’s 50% stake in Lightsource bp.
Biopower and biofuels through
bp’s 50% stake in bp Bunge
Bioenergia.
US biogas.
Hydrogen and carbon capture,
use and storage.
Customers & products
Focuses on customers as
the driving force for innovating
new business models and
service platforms to deliver the
convenience, mobility and energy
products and services of the future.
Responsible for:
Convenience offerings at our
retail sites«, including snacks,
ready meals and coffee.
Fuel sales to customers and
businesses.
Our Castrol lubricants brand sold
through numerous channels.
Our aviation fuelling business.
Next-gen mobility, including
our charging businesses.
Refining & trading – our oil
products businesses.
Production & operations
Brings the operations of our
hydrocarbon business into one
place. It is the operational heart of
bp, from which we can produce the
hydrocarbon energy and products
the world needs – safely, cleanly
and efficiently.
Innovation & engineering
Home to our central engineering,
safety and operational risk
assurance, and digital security
authorities. I&E also aims to act as
a catalyst for creating value from
disruptive opportunities and new
business models.
Responsible for:
Responsible for:
Safe and reliable operations
across all of our oil, gas and
refining activities, including
bpx energy and our strategic
investments with Rosneft
in Russia.
Driving emissions down in
our operations.
Defining bp-wide operating,
engineering and digital standards.
Research and development.
Digital expertise and
transformation.
Capturing, incubating and scaling
ideas from across bp’s global
innovation ecosystem, through
bp ventures and Launchpad.
We believe in becoming a
company that provides
integrated, low carbon energy
solutions for our customers –
bringing together different forms
of energy to give the world what
it wants: clean, affordable and
firm energy.
Dev Sanyal,
EVP gas & low carbon energy
We will unlock the power of
collaborating as one customer-
centric, digital and agile team,
focused on meeting customers’
needs and delivering products
and services fit for today, and
a low carbon future.
Our vision is to build a resilient
hydrocarbons business that leads
the industry. We maintain an
uncompromising focus on safety
and emissions and constantly
challenge ourselves to improve
efficiency.
Emma Delaney,
EVP customers & products
Gordon Birrell,
EVP production & operations
We’ve gathered many of our
most skilled engineers,
technologists, scientists, and
entrepreneurs into a single team
with a purpose – enabling bp to
thrive in the energy transition
through innovation at pace
and scale.
David Eyton,
EVP innovation & engineering
36
bp Annual Report and Form 20-F 2020
Strategic report
See page 38 for more information
on our financial reporting segments.
working with three
integrators, to
facilitate collaboration
and unlock value…
Regions, cities & solutions
brings together the best of bp to
build enduring relationships with
regions, countries, cities and
corporations around the world to
provide innovative, integrated and
decarbonized energy solutions at
scale to help the world reach net
zero and improve people’s lives.
Strategy & sustainability
embeds sustainability at the top of
the organization and forms a single
group-wide approach to strategy
and capital allocation.
Trading & shipping
harnesses the deep expertise of our
existing supply, trading and shipping
businesses. bp already has
world-leading expertise in the
integration of businesses,
customers and markets.
and four teams who
serve as enablers of
business delivery.
Communications & advocacy
helps translate bp’s strategy
into a coherent narrative for staff
and society, manages corporate
reputation and leads policy,
advocacy and campaigns.
Finance
stewards bp’s financial frame,
maintains financial integrity and
manages procurement activities.
People & culture
helps bp recruit world-class talent,
develops them, and supports them
to do their best work.
Legal
delivers legal support to bp, focused
on material risk, value and growth.
And of this team, 38% are women
and 28% identify as racial and ethnic
minorities. This is good progress,
but still not good enough. As a
leadership, we are not yet fully
reflective of bp as a whole or the
communities in which we operate.
See page 57 for more
information on diversity
and inclusion in bp.
From left to right:
Emma Delaney
EVP, customers
& products
Dev Sanyal
EVP, gas & low carbon
energy
David Eyton
EVP, innovation
& engineering
Gordon Birrell
EVP, production
& operations
William Lin
EVP, regions,
cities & solutions
Carol Howle
EVP, trading & shipping
Giulia Chierchia
EVP, strategy &
sustainability
Bernard Looney
Chief executive officer
Geoff Morrell
EVP, communications
& advocacy
Kerry Dryburgh
EVP, people & culture
Eric Nitcher
EVP, legal
Murray Auchincloss
Chief financial officer
See page 78 for our leadership team biographies.
Leadership culture
We are transforming the culture
of bp. It’s all about people and that
begins with leadership. In 2020
we undertook a fundamental
review of our organization and
selected new leaders from the
executive level down. These top
120 leaders were selected
because they reflected a number
of key attributes required to drive
bp’s transformation.
A track record of delivery.
Curious and open-minded.
Purpose-driven.
Lead through our values
– especially safety.
Empathetic.
bp Annual Report and Form 20-F 2020
37
Reinventing bp – our financial reporting segments
Changing how we report
Our new financial reporting model functions across the organization to maximize commercial value along
integrated value chains.
As set out in our organization model on page 36,
operationally, our hydrocarbon businesses,
including refining, will be managed together.
However, the financial results of our oil, gas
and refining operations will be reported
separately, acknowledging opportunities for
commercial integration.
Gas will be reported together with our low carbon
businesses. This recognizes the potential for
increasing integration of gas value chains with our
low carbon businesses. Refining will be reported as
part of the customers & products segment,
recognizing the importance of maintaining our
integrated fuels value chains.
For more information on how our
hydrocarbon operations are split between
the oil production & operations, gas &
low carbon energy, and customers &
products segments visit bp.com.
Gas & low carbon energya comprises
regions with upstream businesses that
predominantly produce natural gas,
gas trading activities and the group’s
renewables businesses, including biofuels,
solar and wind. Gas-producing regions were
previously reported in the Upstream segment,
and our renewables businesses were
previously reported as part of Other
businesses and corporate.
Oil production & operationsa comprises
regions with upstream activities that
predominantly produce crude oil, including
bpx energy. These were previously reported
in the Upstream segment.
Customers & products comprises the
group’s customer-focused businesses,
spanning convenience and mobility, which
includes fuels retail and next-gen offers
such as electrification, as well as aviation,
midstream, and Castrol lubricants. It also
includes our oil products businesses,
refining & trading. The petrochemicals
business will also be reported in restated
comparative information as part of customers
& products up to its sale in December 2020.
This segment is unchanged from the former
Downstream segment with the exception of
the disposal of our petrochemicals business.
The Rosneft segment is unchanged and
continues to include equity-accounted earnings
from our strategic investment in Rosneft.
Other businesses & corporate comprises
our innovation & engineering business
including bp ventures and Launchpad, regions,
cities & solutions; and our corporate activities
& functions.
a The AGT and Middle East regions have been further
subdivided by asset.
See page 36 for our organizational model.
Mapping our 2020 segment reporting to our 2021 financial reporting segmentsb
Oil production
& operations
Gas & low
carbon energy
Customers
& productsd
Rosneft
Other businesses
& corporate
Upstream
Downstream
Oil regionsc
Gas
Gas regionsc
Gas marketing & trading
Integrated gas & power
Customers:
convenience &
mobility
Convenience
Mobility: fuels retail
Mobility: next-gen
Castrol
Aviation, B2B, midstream
Products:
refining & trading
Refining
Oil & oil products
trading
Rosneft
Other businesses
& corporate
Low carbon energy
Low carbon electricity
Bioenergy
CCUS
Hydrogen
Rosneft
bp ventures
Launchpad
Corporate activities
b Not a comprehensive list of businesses reported in each segment.
c Regions disclosed on bp.com under segment financial disclosure framework.
d Includes respective low carbon results, such as bio co-processing.
38
bp Annual Report and Form 20-F 2020
Key performance indicators
Measuring our progress
Strategic report
We assess our performance
across a wide range of measures
and indicators that are consistent
with our strategy and investor
proposition.
Our key performance indicators
(KPIs) provide a balanced set
of metrics that give emphasis to
both financial and non-financial
measures. These help the board
and leadership team assess
performance against our strategic
priorities and business plans.
Our leadership team uses these
measures to evaluate operating
performance and make financial,
strategic and operating decisions.
Remuneration
To help align the focus of our board and
executive management with the interests
of our shareholders, certain measures are
used for executive remuneration.
Key
REM Used for 2020 remuneration policy
See page 103 for more information.
Safety
Sustainable operations
Tier 1 and 2 process safety eventsa
We track tier 1 and tier 2 events and report the
aggregated outcome. Tier 1 events are losses of primary
containment from a process of greatest consequence,
or causing harm to a member of the workforce,
damage to equipment from a fire or explosion, a
community impact or exceeding defined quantities.
Tier 2 events are those of lesser consequence.
Greenhouse gas emissions (MtCO2e)
We provide data on greenhouse gas (GHG) emissions
material to our business on a carbon dioxide-equivalent
basis. This particular KPI comprises Scope 1 (direct)
emissions of CO2 and methane, for 100% emissions
from subsidiaries« and the percentage of emissions
equivalent to our share of joint arrangements« and
associates«, other than bp’s share of Rosneft.
2020
17
2019
26
2018
16
2017
18
2016
16
53
56
61
72
70
98
72
79
2020
2019
2018
2017
84
100
2016
41.3
46.0
46.5
49.4
50.1
Tier 1 process safety events
Tier 2 process safety events
2020 performance
We had fewer tier 1 and tier 2 process safety events
compared with 2019. This may in part be a consequence
of decreased activity during the COVID-19 pandemic,
but we believe that other, more intentional, factors are
also involved, such as our deepening focus on safety
leadership, human performance, and the effectiveness
of core safety processes, such as permit-to-work.
2020 performance
Our Scope 1 (direct) equity share emissions decreased
by 4.7MtCO2e to 41.3MtCO2e in 2020 (46.0MtCO2e
in 2019). The reduction was associated with a number
of factors such as divestments, including of our
Alaska operations, sustainable emissions reductions,
turnarounds, and the impact of COVID-19 on demand.
Sustainable GHG emissions reductions
(MtCO2e)
This measure includes actions taken by our businesses
to improve energy efficiency and reduce methane
emissions and flaring – all leading to ongoing, quantifiable
GHG reductions. These refer to the GHG emissions on
an operational control basisb that would have occurred
had we not made the change i.e. they could be absolute
in nature or underlying. Since 2019, progress against
this target is used as a factor in determining bonuses
for eligible employeesc, including executives.
2020
2019
2018
2017
2016
0.132
2020
0.166
2019
0.198
2018
0.218
2017
0.211
2016
1.0
1.4
1.3
0.5
0.7
2020 performance
We have seen a decrease in RIF compared with 2019
and maintain our focus to drive zero incidents. Since
2015, RIF rates have decreased around 46%.
a This represents reported incidents occurring within bp’s
operational HSSE reporting boundary. That boundary includes
bp’s own operated facilities and certain other locations
or situations.
2020 performance
We delivered 1.0Mte of sustainable emissions reductions
(SERs) from reduction projects such as flaring in Angola,
reduction in water pump fuel gas usage in AGT and in
lower emissions from power import at our
Gelsenkirchen refinery.
b Operational control data comprises 100% of emissions
from activities that are operated by bp.
c This figure was around 37,000 in February 2020. It is now
around 28,600 (as at 10 March 2021) and has been revised in
line with restructuring as part of reinvent bp and reflects a
lower headcount overall.
bp Annual Report and Form 20-F 2020
39
Changes to KPIs
We have removed proved reserves replacement
ratio from our KPIs, as it no longer serves as a
useful measure of our strategic performance.
Reported recordable injury frequencya
Reported recordable injury frequency (RIF) measures
the number of reported work-related employee and
contractor incidents that result in a fatality or injury
per 200,000 hours worked.
Key performance indicators continued
Sustainable operations
Methane intensity (%)
We define methane intensity as the amount of methane
emissions from our upstream oil and gas operations as
a percentage of the gas that goes to market from those
operations. This applies to methane emissions within
our operational control boundary, where we have the
highest degree of control. Methane emissions from
non-producing activities, such as exploration drilling,
are excluded. In 2020 we set an intensity target of
0.20% by 2025, using a measurement approach.
Downstream refining availability (%)
Refining availability represents Solomon Associates’
operational availability for bp-operated refineries.
The measure shows the percentage of the year
that a unit is available for processing after deducting
the time spent on turnaround activity and all
mechanical, process and regulatory downtime.
Refining availability is an important indicator of the
operational performance of our downstream businesses.
Upstream plant reliability (%)
bp-operated upstream plant reliability is calculated
taking 100% less the ratio of total unplanned plant
deferrals divided by installed production capacity.
Unplanned plant deferrals are associated with the
topside plant and, where applicable, the subsea
equipment (excluding wells and reservoir). Unplanned
plant deferrals include breakdowns, which does not
include Gulf of Mexico weather-related downtime.
2020
2019
2018
0.12
2020
0.14
2019
0.16
2018
2017
2016
96.0
2020
94.9
2019
95.0
2018
95.2
2017
95.2
2016
94.0
94.4
95.7
94.7
95.3
2020 performance
Our methane intensity in 2020 was 0.12%,
an improvement from 0.14% in 2019.
2020 performance
Refining availability was higher, reflecting
continued strong operational performance in
our portfolio. This performance is underpinned
by our global reliability programmes.
2020 performance
Operations were strong in 2020 with plant reliability
remaining at 94%.
Upstream unit production costs ($/boe)
The upstream unit production cost is calculated as
production cost divided by units of production. Production
cost does not include ad valorem and severance taxes.
Units of production are barrels for liquids and thousands
of cubic feet for gas. Amounts disclosed are for bp
subsidiaries only and do not include bp’s share of
equity-accounted entities.
Major project delivery
We monitor the progress of our major projects to gauge
whether we are delivering our core pipeline of projects
under construction on time.
Diversity and inclusiond (%)
Each year we report the percentage of women and
individuals from countries other than the UK and the US
among bp’s group leaders.
Projects take many years to complete, requiring differing
amounts of resource, so a smooth or increasing trend
should not be anticipated.
Major projects are defined as those with a bp net
investment of at least $250 million, or considered to
be of strategic importance to bp, or of a high degree
of complexity.
2020
2019
2018
2017
2016
6.39
2020
6.84
2019
7.15
2018
7.11
2017
8.46
2016
4
5
6
7
6
2020
2019
2018
2017
2016
29
30
25
25
24
24
21
24
22
23
2020 performance
Lower production costs compared with 2019 were
mainly due to improved efficiency in our operations and
divestment impacts.
2020 performance
We started up four major projects in India, Oman,
the UK and US.
Women in group leadership
People from beyond the UK
and US in group leadership
2020 performance
Both measures increased. As a global business we are
committed to increasing the diversity of our workforce
and leadership.
d Relates to bp employees.
40
bp Annual Report and Form 20-F 2020
Strategic report
Employee engagement (%)
We conduct an annual employee survey to understand
and monitor levels of employee engagement and identify
areas for improvement.
Financial performance
Underlying replacement cost profit
($ billion)
Underlying RC profit« is a useful measure for investors
because it is one of the profitability measures bp
management uses to assess performance. It assists
management in understanding the underlying trends
in operational performance on a comparable year-
on-year basis. It reflects the replacement cost of
inventories sold in the period and is arrived at by
excluding inventory holding gains and losses« from
profit or loss. Adjustments are also made for non-
operating items« and fair value accounting effects«.
Operating cash flow ($ billion)
Operating cash flow is net cash flow provided by
operating activities, as reported in the group cash
flow statement. Operating activities are the principal
revenue-generating activities of the group and other
activities that are not investing or financing activities.
We believe it is helpful to disclose net cash provided by
operating activities excluding amounts related to the Gulf
of Mexico oil spill because this measure allows for more
meaningful comparisons between reporting periods.
2020
2019
2018
2017
2016
64
65
66
66
73
2020
2019
2018
2017
2016
-20.3
-5.7
4.0
10.0
9.4
12.7
3.4
6.2
0.1
2.6
2020
2019
2018
2017
2016
13.8
12.2
28.2
25.8
26.1
22.9
24.1
18.9
17.6
10.7
2020 performance
The overall employee engagement score saw a
marginal decline since last year. We are working to
identify areas for improvement. Scores prior to 2017
are based on questions on priorities set out in 2012,
so the numbers are not directly comparable.
Profit (loss) for the
year attributable to
bp shareholders
Underlying RC profit for the
year (non-GAAP)
Operating cash flow excluding
amounts related to the Gulf of
Mexico oil spill (non-GAAP)e
Operating cash flow
2020 performance
2020 underlying RC loss was driven by lower oil and gas
prices, significant exploration write-offs and refining
margins and depressed demand. Loss for the year
attributable to bp shareholders included significant
impairments and exploration write-offs. See Financial
statements – Notes 4 and 8 for more information.
2020 performance
Operating cash flow was lower than 2019, reflecting
lower oil and gas realizations, lower refining margins and
fuels volumes partly offset by lower tax payments and
lower working capital« build.
e The dark green bars on the chart do not form part of bp’s
Annual Report on Form 20-F as filed with the SEC.
Total shareholder return (%)
Total shareholder return (TSR) represents the change
in value of a bp shareholding over a calendar year.
It assumes that dividends are reinvested to purchase
additional shares at the closing price on the
ex-dividend date.
Return on average capital employed (%)
Return on average capital employed« (non-GAAP)
gives an indication of a company’s capital efficiency,
dividing the underlying RC profit after adding back
net interest by average capital employed, excluding
cash and goodwill. See page 349 for more information
including the nearest equivalent GAAP data.
2020
2019
2018
2017
2016
-41.4
-41.7
5.8
1.1
(4.6)
0.5
20.0
9.5
29.0
55.5
2020
2019
2018
2017
2016
-3.8
8.9
11.2
5.8
2.8
ADS basis
Ordinary share basis
2020 performance
Reduced TSR reflects a reduction in the share price and
lower dividend in 2020.
2020 performance
The decrease reflects loss due to the impact of lower oil
and gas prices and significant weaker refining margin and
depressed demand.
bp Annual Report and Form 20-F 2020
41
Group performance
Group performance
Financial and operating performance
Sales and other operating revenues
Profit (loss) before interest and taxation
Finance costs and net finance expense relating to pensions
and other post-retirement benefits
Taxation
Non-controlling interests
Profit (loss) for the year attributable to
bp shareholders
Inventory holding (gains) losses«, before tax
Taxation charge (credit) on inventory holding gains and
losses
RC profit (loss)« for the year attributable to
bp shareholders
Net (favourable) adverse impact of non-operating items«
and fair value accounting effects«, before tax
Taxation charge (credit) on non-operating items and fair
value accounting effects, and certain foreign exchange
impacts on the group’s tax charge for the period
Underlying RC profit (loss)« for the year attributable
to bp shareholders
$ million except per share amounts
2020
2019
2018
180,366
278,397
298,756
(21,740)
11,706
19,378
(3,148)
4,159
424
(3,552)
(3,964)
(164)
(2,655)
(7,145)
(195)
(20,305)
2,868
4,026
(667)
9,383
801
(667)
156
(198)
(18,104)
3,515
9,986
16,649
8,263
3,380
(4,235)
(1,788)
(643)
(5,690)
31.5
24.458
9,990
41.0
31.977
12,723
40.5
30.568
Dividends paid per share – cents
– pence
Results
The loss for the year ended 31 December
2020 attributable to bp shareholders was
$20.3 billion, compared with a profit of
$4.0 billion in 2019. Adjusting for inventory
holding losses, replacement cost (RC) loss
was $18.1 billion, compared with a profit of
$3.5 billion in 2019.
After adjusting RC loss for a net charge
for non-operating items of $12.2 billion and
net adverse fair value accounting effects of
$0.2 billion (both on a post-tax basis), underlying
RC loss for the year ended 31 December 2020
was $5.7 billion. The result reflected lower
oil and gas prices, significant exploration
write-offs and lower refining margins and
depressed demand.
The profit for the year ended 31 December
2019 attributable to bp shareholders was
$4.0 billion, excluding inventory holding gains,
RC profit was $3.5 billion. After adjusting RC
profit for a net charge for non-operating items
of $7.2 billion and net favourable fair value
accounting effects of $0.7 billion (both on a
post-tax basis), underlying RC profit for the year
ended 31 December 2019 was $10.0 billion, a
decrease of $2.7 billion compared with 2018.
The decrease was predominantly due to lower
oil and gas prices in the Upstream segment and
a significantly weaker environment in the
Downstream segment.
Non-operating items
In 2020 the net charge for non-operating items
was $12.2 billion, mainly related to impairment
charges, a gain on the disposal of our
petrochemicals business, certain exploration
write-offs (reported within the ‘other’ category),
and restructuring costs associated with the
reinvent bp programme. The impairment charges
mainly relate to producing assets and principally
arose as a result of changes to the group’s oil and
gas price assumptions. Impairment charges also
include amounts relating to the disposal of the
group’s interests in its Alaska business.
In the face of many challenges
in 2020, we strengthened our
finances and drove progress
towards our $35 billion net debt
target. A resilient balance sheet,
a coherent approach to capital
allocation and a disciplined
approach to investment are the
principles which underpin our
financial frame. Our strategy and
financial frame are expected to
drive strong growth, improved
returns and a sustainable
reallocation of our capital
employed toward the energy
transition, all in support of
creating long-term value
for shareholders.
Murray Auchincloss
Group chief financial officer
42
bp Annual Report and Form 20-F 2020
For more information
For a discussion of bp’s financial and operating performance for the year ending
31 December 2018, see bp Annual Report and Form 20-F 2019, pages 36-38 and
50-65 and bp Annual Report and Form 20-F 2018, pages 19-39.
Strategic report
In 2019 the net charge was $7.2 billion, mainly
related to impairment charges, principally
resulting from the announcements to dispose
of certain assets in the US and reclassification
of accumulated foreign exchange losses from
reserves to the income statement on the
formation of the bp Bunge Bioenergia
joint venture«.
See pages 304 and 305 for more
information on non-operating items
and fair value accounting effects.
Taxation
The credit for corporate income taxes was
$4,159 million in 2020 compared with a charge
of $3,964 million in 2019. The decrease mainly
reflects the loss in 2020. The effective tax
rate (ETR) on the loss for the year in 2020
was impacted by the impairment charges
and exploration write-offs. The ETRs for 2020
and 2019 were also impacted by various other
one-off items.
Adjusting for inventory holding impacts,
non-operating items and fair value accounting
effects, the underlying ETR in 2020 was lower
than in 2019, mainly reflecting the exploration
write-offs with a limited deferred tax benefit
and the reassessment of deferred tax asset
recognition. The underlying ETR for 2021 is
expected to be higher than 40% but is sensitive
to the impact that volatility in the current
environment may have on the geographical mix
of the group’s profits and losses. Underlying ETR
is a non-GAAP measure. A reconciliation to
GAAP information is provided on page 348.
$(5.7)bn
underlying replacement
cost (RC) loss
(2019 profit $10.0bn)
$(20.3)bn
loss attributable to
bp shareholders
(2019 profit $4.0bn)
$13.8bn
operating cash flow
excluding Gulf of Mexico
oil spill paymentsa«
(2019 $28.2bn)
a This does not form part of bp’s Annual Report
on Form 20-F as filed with the SEC.
$12.2bn
operating cash flow«
(2019 $25.8bn)
Non-operating items
Gains on sale of businesses and fixed assets
Impairment and losses on sale of businesses and
fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Gulf of Mexico oil spill
Other
Total before interest and taxation
Finance costs
Taxation credit (charge) on non-operating items
Taxation – impact of US tax reform
Taxation – impact of foreign exchange
Effective tax rate
Effective tax rate (ETR) on profit or loss for the year
Underlying ETR«
2020
2,874
(14,369)
(212)
(1,296)
–
(255)
(2,554)
(15,812)
(625)
(16,437)
4,345
–
(99)
(12,191)
2020
17
(14)
$ million
2019
193
(8,075)
(341)
2
–
(319)
(78)
(8,618)
(511)
(9,129)
1,943
–
–
(7,186)
%
2019
49
36
2018
456
(860)
(758)
(726)
17
(714)
(372)
(2,957)
(479)
(3,436)
510
121
–
(2,805)
2018
43
38
bp Annual Report and Form 20-F 2020
43
Group performance continued
Reporting
The group’s organizational structure reflects
the various activities in which bp is engaged.
At 31 December 2020, bp reported Upstream,
Downstream, Rosneft and Other businesses
and corporate.
Upstream’s activities included oil and natural
gas exploration, field development and
production; midstream transportation, storage
and processing; and the marketing and trading
of natural gas, including liquefied natural gas
(LNG), together with power and natural gas
liquids (NGLs). For further details of Upstream’s
activities during the year see page 308.
Downstream’s activities covered convenience
and mobility offers, including next-gen mobility
to our customers. It also included the refining,
manufacturing, marketing, transportation, and
supply and trading of crude oil, petroleum,
lubricants and petrochemicals products.
The Rosneft segment result includes equity-
accounted earnings arising from bp’s interest
in Rosneft.
Other businesses and corporate comprised
the biofuels and wind businesses, the group’s
shipping and treasury functions, and corporate
activities worldwide.
In February 2020 bp announced plans for a
future reorganization of the group’s operating
segments. The group’s segmental reporting
structure described above remained in place
throughout 2020 and changes, as described on
page 38, were effective from 1 January 2021.
Sales and other operating revenues
Upstream
Downstream
Other businesses and corporate
Less: sales and other operating revenues between
segments
Total sales and other operating revenues
RC profit (loss) before interest and tax
Upstream
Downstream
Rosneft
Other businesses and corporate
Consolidation adjustment – UPII«
Net (favourable) adverse impact of non-operating
items and fair value accounting effects
Upstream
Downstream
Rosneft
Other businesses and corporate
Underlying RC profit (loss) before interest and tax
Upstream
Downstream
Rosneft
Other businesses and corporate
Consolidation adjustment – UPII
bp average realizationsa
Crude oilb
Natural gas liquids
Liquids«
Natural gas
US natural gas
Total hydrocarbons«
Average oil marker pricesc
Brent«
West Texas Intermediate«
Average natural gas marker prices
Average Henry Hub« gas priced
$ million
2020
2019
2018
34,197
162,974
1,716
54,501
250,897
1,788
56,399
270,689
1,678
198,887
307,186
328,766
18,521
28,789
30,010
180,366
278,397
298,756
(21,547)
3,418
(149)
(683)
89
4,917
6,502
2,316
(2,771)
75
(18,872)
11,039
16,506
(330)
205
(357)
16,024
(5,041)
3,088
56
(1,040)
89
(2,848)
6,241
(83)
103
1,491
7,752
11,158
6,419
2,419
(1,280)
75
18,791
$ per barrel
61.56
18.23
57.73
38.46
12.91
36.16
14,328
6,940
2,221
(3,521)
211
20,179
222
621
95
1,963
2,901
14,550
7,561
2,316
(1,558)
211
23,080
67.81
29.42
64.98
$ per thousand cubic feet
2.75
1.30
3.39
1.93
3.92
2.43
$ per barrel of oil equivalent
26.31
38.00
43.47
$ per barrel
41.84
39.25
64.21
57.03
71.31
65.20
$ per million British thermal units
2.08
2.63
3.09
pence per therm
Average UK National Balancing Point gas price«
24.93
34.70
60.38
bp average refining marker margin (RMM)«
6.7
13.2
13.1
$/bbl
44
bp Annual Report and Form 20-F 2020
a Realizations are based on sales by consolidated subsidiaries« only, which excludes equity-accounted entities.
b Includes condensate.
c All traded days average.
d Henry Hub First of Month Index.
Strategic report
Upstream
Sales and other operating revenues for
2020 were lower due to lower liquids and gas
realizations, lower gas marketing and trading
revenues and were further impacted by lower
sales volumes.
RC loss before interest and tax for the segment
included a net non-operating charge of $15,768
million. This primarily relates to impairments
associated with revisions to the long-term price
assumptions. See Financial statements – Note 5
for further information. Fair value accounting
effects had an adverse impact of $738 million
relative to management’s view of performance.
The 2019 result included a net non-operating
charge of $6,947 million, primarily related to
impairment charges arising from disposal
transactions. Fair value accounting effects had
a favourable impact of $706 million relative to
management’s view of performance.
After adjusting for non-operating items and fair
value accounting effects, the underlying RC
result before interest and tax was lower in 2020
compared with 2019. This primarily reflected
lower liquids and gas realizations and the impact
of writing down certain exploration intangible
carrying values.
Downstream
Sales and other operating revenues in 2020
were lower than in 2019, mainly due to lower
crude and product prices and the demand
impact of COVID-19.
RC profit before interest and tax for 2020
included a net non-operating gain of $479 million.
The gain reflected a profit of $2.3 billion on
the sale of our petrochemicals business, which
was partially offset by restructuring costs and
impairments. In addition, fair value accounting
effects for 2020 had an adverse impact of
$149 million, compared with a favourable
impact of $160 million in 2019.
After adjusting for non-operating items and
fair value accounting effects, underlying RC
profit before interest and tax for the year was
$3,088 million.
The fuels business reported a lower underlying
RC profit before interest and tax compared
with 2019, due to an exceptionally weak refining
environment, with COVID-19 restrictions
impacting refining utilization and fuel volumes.
The 2020 result also reflects a higher contribution
from supply and trading.
Our fuels marketing business demonstrated
continued resilience, delivering significant profit
in 2020, despite COVID-19 – which adversely
impacted retail fuel and aviation volumes by
14% and 50% respectively.
Rosneft
RC loss before interest and tax for 2020 and
RC profit before interest and tax for 2019 for the
segment included a non-operating charge of
$205 million for 2020 and $103 million for 2019.
Refining loss in 2020 reflects the continued
impact of historically low industry margins.
Although refining availability« was strong at
96%, utilization was around 6% lower than
2019, due to the impact of COVID-19 on demand.
These factors were partially offset by a lower
level of turnaround activity and lower costs.
In the fourth quarter of 2020, we announced
plans to cease production at our Kwinana refinery
and convert it to an import terminal, helping
secure ongoing fuel supply for Western Australia.
We continued to redefine convenience in 2020,
delivering a 6% growth in convenience gross
margin«. We also expanded our retail network
by more than 1,400 sites, to a total of 20,300,
including more than 1,900 strategic convenience
sites«. And we completed the formation of
Jio-bp, our Indian joint venture with Reliance,
helping more than double the number of retail
sites in growth markets«, see page 24.
We also progressed our electrification agenda,
growing our network to 10,100 bp and joint
venture operated electric vehicle charge points«,
see Our strategy on page 15.
The lubricants business reported a lower
underlying RC profit before interest and tax
compared with 2019 and this reflected significant
COVID-19 demand impacts, with volumes 15%
lower for the year. We continued to expand our
service offer in 2020, growing the number of
Castrol branded independent workshops by
more than 4,000 to over 28,000 globally.
The petrochemicals business reported a lower
underlying RC profit before interest and tax
compared with 2019, reflecting the impact of
COVID-19 on demand and a significantly weaker
margin environment. In December we completed
the divestment of bp’s petrochemicals business
to INEOS for a total consideration of $5 billion.
Final payments, totalling $1 billion, were received
in February 2021.
For more information see Additional
information for Downstream on page 318.
After adjusting for non-operating items, the
underlying RC profit before interest and tax in
2020 primarily reflected lower oil prices and
unfavourable foreign exchange and adverse duty
lag effects compared with 2019 underlying profit.
Financial and operating performance for 2020
also reflected the increased average economic
interest that bp holds in Rosneft as a result of
Rosneft’s share buyback programme and the
transaction to sell Rosneft’s business in
Venezuela in exchange for its own shares,
which completed in April 2020.
For more information see Additional
information for Rosneft on page 320.
Other businesses and corporate
RC loss before interest and tax for the year
ended 31 December 2020 was $683 million
(2019 $2,771 million). The 2020 result included
a net charge for non-operating items of $318
million, primarily relating to Gulf of Mexico
oil spill related costs of $255 million and
restructuring costs, partly offset by a gain on
disposal (non-operating items in 2019 $1,491
million). In addition, fair value accounting effects
had a favourable impact of $675 million.
After adjusting for non-operating items and fair
value accounting effects, the underlying RC
loss before interest and tax for the year ended
31 December 2020 was $1,040 million (2019
$1,280 million). This result mainly reflected an
uplift in valuation of a venture investment of
$284 million.
Outlook for 2021
From the oil supply side, limited growth
from non-OPEC+ countries coupled
with active market management from
OPEC+ means that for 2021 we anticipate
a normalization of the currently high
inventory levels.
Oil demand is anticipated to recover in
2021. The speed and degree of the rebound
depends on governments’ policies and
individuals’ self-imposed actions as vaccine
distribution proceeds.
bp Annual Report and Form 20-F 2020
45
Group performance continued
Oil prices have risen since the end of October,
supported by vaccine rollout programmes and
continued active supply management by
OPEC+ countries. Prices are expected to
remain subject to the decisions of OPEC+,
confidence in efforts to manage the rollout of
vaccination and further virus control measures.
We expect the US gas market to tighten in
2021 as supply declines and demand for LNG
exports recovers. The current tightness on
global LNG markets and higher US gas prices
will lift other regional gas prices.
US gas markets are likely to benefit from
lower production and a recovery in international
LNG demand driven by demand in Asia.
In Downstream we expect the outlook for the
first part of the year to remain challenged due
to COVID-19, but to improve. While COVID-19
has had material impacts at the start of the
year, with increased restrictions resulting in
lower product demand, we expect this
uncertainty to improve subject to the
successful rollout of vaccination and virus
control measures. Industry refining margins
and utilization continue to remain restrained
by uncertainty about the pace of demand
recovery. The weak margin environment
combined with continued capacity additions
in developing markets has prompted a raft of
third-party closure announcements. However,
these closures are unlikely to be sufficient to
see a sustained rebound in margins to
pre-COVID levels in 2021.
Full-year 2021 underlying production« is
expected to be slightly higher than 2020 due
to the ramp-up of major projects«, primarily
in gas regions, partly offset by the impacts
of reduced capital investment and decline in
lower-margin gas assets. Reported production
is expected to be lower due to the impact of
the ongoing divestment programme.
Other businesses and corporate charges for
2021, excluding non-operating items, fair
value accounting effects and foreign exchange
volatility impact, are expected to be $1.2-1.4
billion although the quarterly charge may vary
quarter to quarter.
Cash flow and net debt information
Operating cash flow excluding Gulf of Mexico oil spill
paymentsa
Operating cash flow
Net cash used in investing activities
Net cash provided by (used in) financing activities
Cash and cash equivalents at end of year
Capital expenditure«
Organic capital expenditure«
Inorganic capital expenditure«
Divestment and other proceeds
Divestment proceeds«
Other proceeds
Debt
Finance debt
Net debt«
Finance debt ratio« (%)
Gearing« (%)
Gearing including leases« (%)
a This does not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
$ million
2020
2019
2018
13,770
12,162
(7,858)
3,956
31,111
28,199
25,770
(16,974)
(8,817)
22,472
26,091
22,873
(21,571)
(4,079)
22,468
(12,034)
(2,021)
(15,238)
(4,183)
(15,140)
(9,948)
(14,055)
(19,421)
(25,088)
5,480
1,106
6,586
72,664
38,941
45.9%
31.3%
36.0%
2,201
566
2,767
67,724
45,442
40.2%
31.1%
35.3%
2,851
666
3,517
65,132
43,477
39.1%
30.0%
NA
Operating cash flow for the year ended
31 December 2019 was $25.8 billion, $2.9 billion
higher than 2018. Operating cash flow in 2019
reflected $2.7 billion of pre-tax cash outflows
related to the Gulf of Mexico oil spill. Compared
with 2018, operating cash flows in 2019 also
reflected the favourable effect of an estimated
$2.0 billion of lease payments being classified
as financing cash flows from 1 January 2019
following the implementation of IFRS 16.
Movements in working capital adversely
impacted cash flow in the year by $2.9 billion,
including an adverse impact on working capital
from the Gulf of Mexico oil spill of $2.6 billion.
Operating cash flow
Operating cash flow for the year ended
31 December 2020 was $12.2 billion, $13.6 billion
lower than 2019. Operating cash flow in 2020
reflects $1.8 billion of pre-tax cash outflows
related to the Gulf of Mexico oil spill. Compared
with 2019, operating cash flows in 2020 reflected
lower oil and gas realizations, lower refining
margins and lower fuels volumes partly offset
by lower tax payments and lower working
capital« build.
Movements in working capital adversely
impacted cash flow in the year by $0.1 billion,
including an adverse impact on working capital
from the Gulf of Mexico oil spill of $1.6 billion.
Other working capital effects, principally a
decrease in inventory and other current and
non-current assets partially offset by a decrease
in other current and non-current liabilities, had
a favourable effect of $1.5 billion. bp actively
manages its working capital balances to optimize
and reduce volatility in cash flow.
46
bp Annual Report and Form 20-F 2020
Strategic report
Net cash used in investing activities
Net cash used in investing activities for the
year ended 31 December 2020 decreased
by $9.1 billion compared with 2019.
The decrease mainly reflected lower capital
expenditure, particularly due to payments
of $3.5 billion in 2019 for the acquisition of
unconventional onshore US oil and gas assets
from BHP, and $3.9 billion of disposal proceeds
from the petrochemicals divestment.
Total capital expenditure for 2020 was
$14.1 billion (2019 $19.4 billion), of which
organic capital expenditure was $12.0 billion
(2019 $15.2 billion) in line with the guidance
given in April. Sources of funding are fungible,
but the majority of the group’s funding
requirements for new investment comes
from cash generated by existing operations.
We expect 2021 total capital expenditure,
including organic capital expenditure, to be
around $13 billion.
Total divestment and other proceeds for 2020
amounted to $6.6 billion, including $3.9 billion
of proceeds from the petrochemicals divestment
and $1.1 billion other proceeds. Other proceeds
represented a loan repayment relating to the
TANAP pipeline refinancing; and proceeds in
relation to the sale of interests in bp’s retail
property portfolio in the UK and New Zealand.
Total divestment and other proceeds for 2019
amounted to $2.8 billion, including $0.6 billion
received in relation to the sale of an interest in
bp’s retail property portfolio in Australia. The
proceeds from the UK, New Zealand and
Australia property transactions are reported
within financing activities in the group cash
flow statement.
bp has completed or agreed transactions for
over half of its target of $25 billion in proceeds by
2025. bp expects proceeds from divestments
and other disposals of $4-6 billion in 2021,
weighted towards the second half.
Net cash provided by (used in)
financing activities
Net cash provided by financing activities for the
year ended 31 December 2020 was $4.0 billion,
compared with net cash used of $8.8 billion in
2019. This was mainly due to the issue of
perpetual hybrid bonds with a US$ equivalent
value of $11.9 billion.
Group reserves and production (including Rosneft segment)a
Estimated net proved reserves (net of royalties)
Liquids (mmb)
Natural gas (bcf)
Total hydrocarbons (mmboe)
Of which:
Equity-accounted entitiesb
Production (net of royalties)
Liquids (mb/d)
Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)
Of which:
Subsidiaries
Equity-accounted entitiesc
2020
2019
2018
10,661
42,467
17,982
11,478
45,601
19,341
11,456
49,239
19,945
10,100
9,965
9,757
2,106
7,929
3,473
2,146
1,326
2,211
9,102
3,781
2,420
1,360
2,191
8,659
3,683
2,328
1,355
a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes BP’s share of Rosneft. See Supplementary information on oil and natural gas on page 231 for further information.
c Includes BP’s share of Rosneft. See Oil and gas disclosures for the group on page 312 for further information.
Total dividends distributed to shareholders in
2020 were 31.5 cents per share, 9.5 cents lower
than 2019. This amounted to a total distribution
to shareholders of $6.3 billion in 2020. In 2019
the total distribution to shareholders was
$8.3 billion, of which shareholders elected to
receive $1.4 billion in shares under the scrip
dividend programme. The board decided not
to offer a scrip dividend alternative in respect
of the 2020 dividends.
Debt
Finance debt at the end of 2020 increased by
$4.9 billion from the end of 2019. The finance
debt ratio at the end of 2020 increased to 45.9%
from 40.2% at the end of 2019. Net debt at the
end of 2020 decreased by $6.5 billion from the
2019 year-end position. Gearing at the end of
2020 increased to 31.3% from 31.1%, reflecting
significant impairments and exploration write-
offs, offset by the hybrid bond issue in June
2020. Net debt and gearing are non-GAAP
measures. See Financial statements – Notes 26
and 27 for further information on finance debt and
net debt.
For information on financing the
group’s activities see Financial
statements – Note 29 and Liquidity
and capital resources on page 306.
Group reserves and production
Total hydrocarbon proved reserves at
31 December 2020, on an oil equivalent basis
including equity-accounted entities, decreased
by 7% compared with 31 December 2019.
Natural gas represented about 41% (47% for
subsidiaries and 36% for equity-accounted
entities) of these reserves. The change includes
a net decrease from acquisitions and disposals
of 1,069mmboe (decrease of 1,072mmboe
within our subsidiaries and increase of
3mmboe within our equity-accounted entities).
Acquisition and divestment activity occurred
in our equity-accounted entities in Russia,
and divestment activity in our subsidiaries
in the US including Alaska.
Total hydrocarbon production for the group
was 8% lower compared with 2019. The
decrease comprised an 11% decrease (6%
decrease for liquids and 16% decrease for
gas) for subsidiaries and a 2% decrease (4%
decrease for liquids and 2% increase for gas)
for equity-accounted entities.
bp Annual Report and Form 20-F 2020
47
Sustainability
Our approach to sustainability
E n g a g i n g stakeholders
Our
values and
foundations
E
mbedding int o o u r
D N A
Sustainability frame
Sustainability is a critical foundation of our
strategy. Our new sustainability frame links our
strategy to our purpose – to reimagine energy
for people and our planet.
Our frame focuses on three areas where we
believe we can make the biggest difference, with
aims and objectives linked to the UN Sustainable
Development Goals.
Getting to net zero.
Caring for our planet.
Improving people’s lives.
You can read more about our focus areas,
sustainability foundations, our work to make
sustainability more integral to our thinking and
how we’re expanding our engagement with
stakeholders at bp.com/sustainability
Reporting on sustainability
We updated our sustainability materiality
assessment process in 2020 to take into account
our new sustainability frame. You can read more
about this process in the bp Sustainability Report
2020. For the purposes of this section we have
covered material issues, along with additional
non-financial information in the following areas:
Net zero aims, see pages 49-51.
Climate change and the environment,
see pages 52-55.
Safety, see pages 59-60.
People and value to society,
see pages 57-58.
Business ethics and accountability,
see page 61.
bp non-financial reporting information statement
Produced in compliance with Sections 414CA and 414CB of the Companies Act. Information incorporated by cross reference.
Requirement
a. Environmental matters
b. Employees
Relevant policies and standards
Net zero aims
TCFD (governance and risk)
Sustainability frame
Biodiversity position (online)
Reinvent bp guidelines
bp values and code of conduct (online)
c. Social matters
Sustainability frame
d. Respect for human rights
e. Anti-corruption and anti-bribery
Description of principal risks
relating to matters (a-e above)
–
Business and human rights policy (online)
Modern slavery statement (online)
Labour rights and modern slavery
principles (online)
Code of conduct (online)
Anti-bribery and corruption policy
Code of conduct (online)
Business model description
Business model – pages 16-17.
Description of non-financial KPIs
Key performance indicators – pages 39-41.
Relevant information
Information related to policies, any due
diligence process and the outcome (a-e)
Climate change and the environment – pages 53-57.
Managing our environmental impacts – page 56.
Our operating management system« (OMS) – page 60.
Decision making by the board – page 82.
People and society – pages 57-58.
Safety – pages 59-60.
Our values and code of conduct – page 61.
How we engage with our stakeholders (Pulse survey) – page 63.
How the board engaged with stakeholders (Workforce) – page 86.
Managing our environmental impacts – page 56.
Our operating management system – page 60.
Value to society – page 58.
Decision making by the board – page 82.
Human rights – page 58.
How we engage with our stakeholders (Our human rights policy)
– page 63.
Our values and code of conduct – page 61.
Business ethics and accountability – page 61.
Our partners in joint arrangements – page 60.
How we manage risk – pages 64-66.
Risk factors – pages 67-70.
TCFD (climate-related risk management), pages 55-56.
48
bp Annual Report and Form 20-F 2020
Our net zero aims
In February 2020 we set out
our ambition to be a net zero
company by 2050 or sooner.
And to help the world get to
net zero. This ambition is
supported by 10 aims: five to
help us become a net zero
company, and five to help the
world meet net zero. Taken
collectively, these set out a path
that we believe is consistent
with the Paris goals.
Strategic report
Our net zero targets and aims at a glance
Aims
2020 performance
2025 target
2030 aims
2050, or sooner, aims
16%a
9%ab
20%
30-35% 100%
20%
35-40% 100%
0.6%ab
5%
>15% 50%
0.12%c
$750me
0.20%
(based on our new
measurement
approach)d
$3-4bn
Timeline to achieve
50%
reduction to follow
~$5bn
Aim 1
Aim 2
Aim 3
Aim 4
Aim 5
What we mean by net zero
When we talk about helping the world get to net zero we mean achieving a balance between sources of anthropogenic emissions and removal by sinks
of greenhouse gases, as set out in Article 4.1 of the Paris Agreementf. When talking about bp becoming a net zero company by 2050, or sooner, in the
context of our new ambition and aims 1 and 2, this means achieving a balance between (a) the relevant Scope 1 and 2 emissions associated with our
operations (aim 1), or Scope 3 emissions associated with carbon in bp’s net share of production of oil and gas excluding Rosneft (aim 2), and (b) the total
of applicable deductions from activities such as sinks, for example carbon capture, use and storage (CCUS) and land carbon projects, which we allow for
in our methodology.
Our aim 1 is to be net zero
across our entire operations on an
absolute basis by 2050 or sooner.
This aim relates to our Scope 1 (from running the
assets within our operational control boundary)
and Scope 2 (associated with producing the
electricity, heating and cooling that is bought in
to run those operations) GHG emissions.
Our performance in 2020
Our combined Scope 1 and Scope 2 emissions,
covered by aim 1, decreased by 16% from
54.4MteCO2e in 2019 to 45.5MteCO2e in 2020.
Scope 1 (direct) emissions covered by aim 1
decreased by 15% to 41.7MteCO2e in 2020, from
49.2MteCO2e in 2019. Of those Scope 1
emissions, 39.8MteCO2e were from CO2 and
1.9MteCO2e from methane.
Scope 2 (indirect) emissions decreased by
1.4MteCO2e, to 3.8Mte CO2e, a 27% reduction
compared to 2019. Decreases resulted from
SERs, reduced energy requirement following
COVID-19 demand reduction and also include
a 1MteCO2e reduction in reported emissions
from our Whiting refinery, which in 2020 put an
agreement in place to purchase electricity from
our Whiting clean energy facility.
Our aim 2 is to be net zero on an
absolute basis across the carbon
in our upstream oil and gas
production« by 2050 or sooner.
This is our Scope 3 aim and is on a bp equity
share basis excluding Rosneft. Emissions are
broadly equivalent to the GHG Protocol, Scope 3,
category 11g, with the specific scope of upstream
production volumes.
Our performance in 2020
The estimated emissions from the carbon in our
Upstream oil and gas production were equivalent
to 328MteCO2e in 2020, a reduction of
approximately 9% compared to 361MteCO2eb
in 2019.
a Reductions against the 2019 baseline.
b The baseline year for our aims 1, 2 and 3 is 2019. Following publication of the bp Annual Report and Form 20-F 2019, some data
improvements related to the reported 2019 figures for aims 2 and 3 were identified. Although these are not considered to be
material, for each of aims 2 and 3 the 2019 figure has been adjusted.
c The 2020 methane intensity is calculated using existing methodology and, while it reflects progress in reducing methane emissions,
will not directly correlate with progress towards delivering the 2025 target under aim 4.
d We aim to have this in place by end of 2023.
e Aim 5 non-oil and gas activities included a partial acquisition payment for the US offshore wind partnership with Equinor, our
investments in electrification and advanced mobility, and investment into activities through bp ventures and Launchpad.
f Article 4.1 of the Paris Agreement: In order to achieve the long-term temperature goal set out in Article 2, Parties aim to reach global
peaking of greenhouse gas emissions as soon as possible, recognizing that peaking will take longer for developing country parties,
and to undertake rapid reductions thereafter in accordance with best available science, so as to achieve a balance between
anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century, on the basis of
equity, and in the context of sustainable development and efforts to eradicate poverty.
g See ghgprotocol.org for the full list of categories.
bp Annual Report and Form 20-F 2020
49
Sustainability continued
Our aim 3 is to cut the carbon
intensity of the products we sell
by 50% by 2050 or sooner.
This is a lifecycle carbon intensity approach,
per unit of energy. It covers marketing sales of
energy products and potentially, in future, certain
other products, for example, associated with
land carbon projects (79.3gCO2e/MJ in 2019a).
In 2020, while we made progress in increasing
the marketed sales of low carbon products, the
reduction in the bp carbon intensity was largely
a result of the reduction in sales of refined
products, due to COVID-19.
See the basis of reporting for the definition of
marketed sales and the list of energy products
covered at bp.com/basisofreporting.
Our performance in 2020
Average emissions intensity of marketed
energy products (gCO2e/MJ)«
Average emissions
intensity of marketed
energy products
Refined energy products
Gas products
Bio-products
Power products
2020
2019
78.8
92.6
71.6
28.2
43.0
79.3
92.8
71.6
28.8
43.8
Streamlined energy and carbon reporting (SECR) information
Further information on our greenhouse gas (GHG) emissionsb, energy consumption and energy efficiency is set out below and includes disclosures in
respect of the SECR requirements.
Operational controlc
Scope 1 (direct) emissions
UK and offshore
Global (excluding UK and offshore)
Scope 2 (indirect) emissionsd
UK and offshore
Global (excluding UK and offshore)
Energy consumptione
UK and offshore
Global (excluding UK and offshore)
Unit
MteCO2e
MteCO2e
MteCO2e
MteCO2e
MteCO2e
MteCO2e
GWh
GWh
GWh
Ratio of Scope 1 (direct) and Scope 2 (indirect) GHG emissions to gross productionf
UK and offshore
Global (excluding UK and offshore)
teCO2e/te
teCO2e/te
teCO2e/te
2019
49.2
2018
48.8
2017
50.5
5.2
5.4
6.1
0.22
0.22
0.24
2020
41.7
1.7
40.0
3.8
0.04
3.77
180,004
7,005
172,999
0.20
0.17
0.20
Energy efficiency measures
Since 2016 we have delivered 4.9Mte of sustainable emissions reductions (SERs)« across our operated sites. This is our key metric for tracking annual
reductions in greenhouse gas (GHG) emissions from energy efficiency savings and direct GHG emissions. We set annual internal targets for the delivery
of SERs across bp.
In 2020 we delivered 1MteCO2e of SERs. These included reductions in flaring, direct methane emissions and energy efficiency savings.
For example, our operations in the AGT region reduced fuel use for water injection pumps through energy efficiency optimization resulting in a
55kteCO2e reduction of Scope 1 emissions. Further SERs include those delivered by our US onshore operations, bpx energy of over 245kteCO2e
– driving operational efficiencies and substantively reducing our methane emissions profile. Our assets in the Permian region delivered 94kteCO2e
of SERs. The largest of these projects was construction and delivery of a centralized facility and electrification of certain operations combined with
use of renewable electricity.
bp equity sharebg
Our Scope 1 (direct) equity share emissions decreased by 4.7MtCO2e to
41.3MtCO2e in 2020 (46.0MtCO2e in 2019). The reduction was associated
with a number of factors such as divestments, including of our Alaska
operations, turnarounds, and the impact of COVID-19 on demand.
Scope 1 (direct) emissions
Scope 2 (indirect) emissions
Total
2020
2019
2018
41.3
4.2
45.5
46.0
5.7
51.7
46.5
5.7
52.2
a The baseline year for our aims 1, 2 and 3 is 2019. Following publication of the bp Annual Report
and Form 20-F 2019, some data improvements related to the reported 2019 figures for aims 2 and
3 were identified. Although these are not considered to be material, for each of aims 2 and 3 the
2019 figure has been adjusted.
b Our approach to reporting GHG emissions broadly follows the IPIECA/API/IOGP Petroleum
Industry Guidelines for Reporting GHG Emissions. We calculate CO2 emissions based on the fuel
consumption and fuel properties for major sources. We report CO2 and methane. We do not
include nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride as they are
not material to our operations and it is not practical to collect this data.
c Operational control data comprises 100% of emissions from activities operated by bp, going
beyond the IPIECA guidelines by including emissions from certain other activities such as
contracted drilling activities.
d Value rounded to one decimal place.
e Energy content of flared or vented gas is excluded from energy consumption reported as although
they reflect loss of energy resources, they do not reflect energy use required for production or
manufacturing of products.
f Gross production comprises upstream production, refining throughput and petrochemicals
produced.
g bp equity share data comprises 100% of emissions from subsidiaries and the percentage of
emissions equivalent to our share of joint arrangements and associates, other than bp’s share
of Rosneft.
50
bp Annual Report and Form 20-F 2020
Strategic report
collaborations. We will continue to run
recruitment campaigns and advertise our
products, services and partnerships – although
we aim for these to be increasingly low carbon.
the membership. We will make the case for our
views on climate change and we will be
transparent where we differ. And where we can’t
reach alignment, we will be prepared to leave.
Our aim 4 is to install
methane measurement at
all our existing major oil and
gas processing sites by 2023,
publish the data, and then drive
a 50% reduction in methane
intensity« of our operations.
And we will work to influence our joint
ventures« to set their own methane intensity
targets of 0.2%.
In 2020 we set an intensity target of 0.20%
by 2025, using a measurement approach.
To reduce our methane intensity, we will
focus on achieving reductions across our key
methane sources.
Our performance in 2020
Our methane intensity in 2020 was 0.12%,
an improvement from 0.14% in 2019.
In 2020 methane emissions from upstream
operations, used to calculate our intensity,
decreased by 22% to 71.6kt in 2020, down from
92.2kt in 2019. Marketed gas was 3,075bcf in
2020. This reduction in methane intensity was
due to the Alaska and bpx energy divestments
in 2020 and from SER projects and flaring
reductions, the largest reductions being
delivered in bpx energy and Angola.
Our aim 5 is to increase the
proportion of investment
we make into our non-oil
and gas businesses.
Over time, as investment goes up in low and no
carbon, we see it going down in oil and gas. We
are aiming for up to an eight-fold scaling up of our
investment in low carbon energy by 2025 and a
ten-fold scaling up by 2030, to around $5 billion a
year. In 2020 we invested $750 million, compared
to more than $500 million in 2019.
See page 22 for more on our
investment in line with aim 5.
We are involved in advocacy activities related
to well-designed policies, primarily carbon
pricing in the US, through our support for
regional initiatives.
bp.com/policyandadvocacy
Our aim 7 is to incentivize our
global workforce to deliver on
our aims and mobilize them to
become advocates for net zero.
We want to help our employees understand what
net zero means and the part they can play –
through education and training programmes. We
want to incentivize employees, which is why in
2019 we linked our annual cash bonus for eligible
employees, including the bp leadership team, to
sustainable emissions reductions (SERs). We
have exceeded targeted delivery of SERs in both
2019 and 2020, though in 2020, bp decided not
to pay an annual bonus due to the prevailing
economic and financial environment.
In 2020 for senior leaders we increased emphasis
on low carbon, moving from 5% to 30% of senior
leaders’ equity awards linked to low carbon. And
for the bp leadership team, 25% of performance-
based pay was linked to delivery of our purpose.
The measures for the 2021 annual bonus for the
wider workforce are aligned to bp’s strategy and
net zero ambition and tied to a balanced
scorecard consisting of safety and sustainability,
operations and financial measures.
In February 2021, we introduced the reinvent bp
share award to incentivize our employees in
meeting our aims. All employees will receive a
one-off grant of either shares or share options
that will become available to keep, sell or transfer
in the first quarter of 2025.
See the Directors’ remuneration
report on pages 103-126 for more detail.
Five aims to help the world get to
net zero
Our aim 6 is to more actively
advocate for policies that support
net zero, including carbon pricing.
We have stopped corporate reputation
advertising campaigns and this is enabling us to
re-direct resources to promote climate policies. In
future, any corporate advertising will be to push
for well-designed climate policy; communicate
our net zero ambition; invite ideas; or build
Our aim 8 is to set new
expectations for our relationships
with trade associations
around the globe.
We belong to associations that offer
opportunities to share good practices and
collaborate on issues of importance to our sector.
We aim for alignment between our policies and
those of trade associations that we are a member
of but understand that associations’ positions
reflect a compromise of the assorted views of
We published our first trade associations review
in early 2020, and left three associations where
we assessed climate positions as not aligned.
Since then, we have made interventions where
our views have not aligned – these occurred in
the area of carbon pricing with the Canadian
Association of Petroleum Producers and the
Netherlands Employer Association, VNO-NCV.
In 2021 we intend to publish an update on our
relationships with trade associations which will
focus on our engagement with five partially
aligned associations.
bp.com/tradeassociations
Our aim 9 is to be recognized
as an industry leader for the
transparency of our reporting.
On 12 February 2020, we declared our support
for the recommendations of the Task Force on
Climate-related Financial Disclosures (TCFD). We
intend to work constructively with the TCFD and
others – such as the Sustainability Accounting
Standards Board – to develop good practices
and standards for transparency.
See pages 52-55 for our expanded
TCFD disclosures.
Our aim 10 is to launch a new
team to create integrated clean
energy and mobility solutions.
We launched our regions, cities and solutions
team in 2020. It will help countries, cities and
corporations around the world decarbonize.
We have announced our aim to partner with
10-15 cities globally over the next decade to help
them achieve their climate goals. And we will
work with three industrial sectors – high tech
and consumer products, heavy transport and
heavy industries – as they shape their energy
transition journeys.
In 2020 we’ve formed strategic partnerships with
Aberdeen, Houston and Microsoft. We’ve also
agreed to provide additional renewable energy
to Amazon, helping them toward their ambition
to decarbonize.
bp.com/RCS
bp Annual Report and Form 20-F 2020
51
Sustainability continued
Climate change and
the environment
Recommended disclosure:
a. Describe the board’s oversight of climate-
related risks and opportunities.
The role of the board is to promote bp’s
sustainable success for the benefit of its
members, generating value for shareholders
while having regard to the interests of our other
stakeholders, the impact of our operations on
the communities where we operate and the
environment. In performing this role, the board
is responsible for oversight of the overall conduct
of the group’s business, which extends to
setting our strategy and approach to the
energy transition.
The board and its associated committees,
including the safety and sustainability, audit,
people and governance and remuneration
committees, where appropriate, have oversight
of climate-related matters, which include climate
risks and opportunities. They are updated on
these matters frequently, a process which is
managed by our company secretary’s office,
which works closely with teams in bp to develop
materials that assist the board or committee to
discharge its responsibilities, including those
related to climate.
In 2020 these processes included formal analysis
of bp’s net zero ambition and aims, briefings with
subject matter experts, reviews of regulatory
correspondence regarding prior year climate
disclosures, virtual site visits and the preparation
and consideration of corporate reporting
documents and AGM materials.
During 2020, climate matters were included on
the agenda at every board meeting. Agendas are
now structured along four distinct pillars: strategy,
performance, people and governance.
The safety and sustainability committee’s remit
was extended from the beginning of 2020 to
provide oversight of the effectiveness of the
implementation of bp’s sustainability frame.
This includes reviewing that appropriate
progress is being made against our net zero,
people and planet aims. The committee will
continue to cover existing sustainability-related
activities, including the oversight of operational
sustainability risks.
The world needs more energy
to fuel prosperity and improve
standards of living for a growing
global population. This energy
must be delivered in affordable and
reliable ways, but it must also be
lower carbon.
Climate-related financial disclosures
We support the recommendations of the Task
Force on Climate-related Financial Disclosures
(TCFD), which was established by the Financial
Stability Board with the aim of improving the
reporting of climate-related risks and
opportunities. We announced in 2020 that we
intend to work constructively with the TCFD,
and others, to develop good practices and
standards for transparency. Our latest reporting
provides information supporting the TCFD’s
recommended disclosures.
We responded to the FCA consultation on
climate-related financial disclosures and welcome
the new listing rule.
Governance
TCFD recommendation: Disclose the
organization’s governance around climate-
related issues and opportunities.
From 1 January 2021, bp implemented a new,
simplified system of sustainability governance
encompassing the board, its associated
committees and the leadership team. This
structure will enhance oversight of bp’s new
sustainability frame, which focuses on three
areas: net zero, people and planet. The remit of
the board and its committees under our new
governance framework is set out on page 88.
Terms of reference for the board and its
committees are available at bp.com/governance.
52
bp Annual Report and Form 20-F 2020
The role of the audit committee is to monitor
the effectiveness of bp’s financial reporting,
systems of internal control and risk
management, and the integrity of bp’s external
and internal audit processes. In fulfilling this
purpose, the committee has oversight of
financial disclosure, including TCFD reporting.
The role of the remuneration committee is to
recommend to the board the remuneration
policy for executive directors and the
leadership team. It also reviews workforce
remuneration and monitors related policies,
satisfying itself that incentives and rewards are
aligned to bp’s strategy, culture and long-term
sustainable success. This includes climate-
related matters.
The role of the people and governance
committee (formerly the nomination and
governance committee) is to oversee a diverse
succession pipeline and to review workforce
policies and practices, monitoring their
consistency with bp’s purpose, strategy and
values. This helps ensure that we have the
right people to deliver our strategy and net
zero ambition.
Pursuing a strategy consistent
with the Paris goals
Strategy has been the core focus of every
board meeting since the beginning of 2019.
Throughout 2020 the board worked closely
with the leadership team in developing our
new strategy. In August 2020 the chairman
outlined the key judgements the board had
applied to their decision making regarding bp’s
strategy, financial frame and investor
proposition. As a result, the board considers
that the strategy allows us to be flexible to
adapt to market changes and scenarios to
remain consistent with the Paris goals.
The role of the board in evaluating
material capex consistency with Paris
The board assesses the impact of portfolio
changes, such as strategic acquisitions and
the allocation of capital. It also considers
specific investment cases which have been
approved by the resource commitment
meeting, see page 29.
Strategic report
Recommended disclosure:
b. Describe management’s role in assessing
and managing climate-related risks
and opportunities.
The assessment and management of climate-
related matters is embedded across bp at various
levels and delegated authority flows down from
the board, see page 29.
From 1 January 2021, a new executive level
governance forum, the group sustainability
committee, will provide internal oversight of
bp’s progress against the aims and objectives
in the sustainability frame, including net zero.
This group is chaired by the EVP strategy &
sustainability (S&S) and comprises members of
the bp leadership team. The group sustainability
committee plans to meet on a quarterly basis
to review progress within entities against the
sustainability frame and decide on critical
strategic positions related to sustainability that
present risks or opportunities to delivery. The
EVP S&S will report to the main board and
committees as required.
The group operational risk committee will
continue to provide oversight of safety and
operational risk management performance for
the group, where appropriate, which includes
sustainability-related risks such as modern
slavery and severe weather.
Climate-related matters were discussed at
each of the leadership team meetings in 2020,
including the development of bp’s net zero
ambition and aims ahead of discussion with
the board.
The leadership team is supported by bp’s
senior-level leadership and their respective
teams, with dedicated business and functional
expertise focused on climate-related matters.
This includes our health, safety, environment
and carbon, strategy and sustainability and group
policy and economics teams.
Alignment between group, business and
functional leaders is fostered through cross-
functional bodies.
Climate governance: management of climate-related matters
As at 1 January 2021
bp board level
Board
Safety and sustainability
committee
Audit committee
Remuneration committee
People and governance
committee
bp leadership team
Group sustainability
committee
Chair: EVP S&S
Oversight of sustainability
matters.
EVP level
Issues and advocacy
meeting
Chair: EVP S&S, EVP C&A
Policy and advocacy issues,
including those related to
climate matters.
SVP level
Corporate reporting
steering
Chair: CFO, EVP C&A,
EVP S&S
Development and oversight
of financial and non-financial
reporting, including TCFD.
Group operational risk
committee
Chair: CEO
Oversight of the group’s
safety and operational risk
management performance,
safety agenda and priorities.
Sustainability forum
Chair: SVP sustainability
Focused on sustainability plans and progress. Brings together previously
separate committees, including carbon steering group, policy and advocacy,
and human rights.
Production & operations carbon table
Chair: SVP HSE & carbon, P&O
Focuses on the delivery of lower carbon plans in P&O
– particularly in relation to net zero aims 1 and 4.
Cross bp meetings and forums
Meetings and forums to allow cross-group discussions and integration.
bp Annual Report and Form 20-F 2020
53
Strategic implications of climate change
In the bp Energy Outlook 2020 we describe
the potential implications of climate change and
the energy transition on both primary energy
demand and the energy system, through three
long-term scenarios: Rapid, Net Zero and
Business-as-usual.
These are summarized on page 11 and further
analysis by country and region, energy sector and
fuel type can be found in the bp Energy Outlook,
available at bp.com/energyoutlook.
The transition to a lower carbon economy
presents both risks and significant business
opportunities for bp. Climate-related physical and
transition risks are managed and reported as part
of our group-wide risk management process
described on pages 64-66.
Climate-related risks and opportunities associated
with the energy transition were taken into
consideration alongside other inputs in
developing our new ambition, aims and strategy.
For more information about how our new
organizational model and financial reporting
segments see pages 36-38. For more on our
new financial frame see page 22.
Risk management
TCFD recommendation: Disclose how the
organization identifies, assesses and manages
climate-related risks.
Recommended disclosure:
a. Describe the organization’s processes for
identifying and assessing climate-related risks.
bp’s risk management system, described on
page 64, is designed to address all types of risks
including our principal risks and uncertainties
described in Risk factors on page 67.
As part of this system our operating businesses,
integrators and enablers (see page 36) are
responsible for identifying, assessing, managing,
and monitoring risks associated with their
business area. Risks are assessed in line with
bp’s risk management policy and this includes an
impact and likelihood assessment which
supports relative prioritization.
Climate-related risks are classified in alignment
with TCFD’s description of physical and
transition risks:
Strategic resilience
We believe our strategy is resilient to the range
of energy transition pathways and scenarios
including Paris, see page 11.
Physical risks – risks related to the physical
impacts of climate change including event-
driven risks such as changes in the severity
and/or frequency of extreme weather events.
For more information on our financial resilience,
including our revised long-term price assumptions
and impairment testing, see page 28. For
information on the resilience of our individual
investments, including our governance structure
and investment process, see page 29.
Our strategy is validated annually by the board
to ensure it remains relevant and resilient, as
part of our standard governance processes.
Elements of the strategy may be refreshed
earlier if there are significant changes in
external or internal environment.
Transition risks – risks related to the transition
to a lower carbon economy including
policy and legal, technology, markets and
reputational risks.
The potential material impacts of such climate-
related risks are described in Risk factors,
see page 67.
Recommended disclosure:
b. Describe the organization’s processes for
managing climate-related risks.
c. Describe how processes for identifying,
assessing and managing climate-related risks
are integrated into the organization’s overall risk
management.
Risks which may be identified include potential
effects on operations at asset level, performance
at business level and developments at regional
level from extreme weather or the transition to a
lower carbon economy.
Sustainability continued
Strategy
TCFD recommendation: Disclose the actual
and potential impacts of climate-related risks
and opportunities on the organization’s
business, strategy and financial planning
where such information is material.
Recommended disclosure:
a. Describe the climate-related risk and
opportunities that the organization has
identified over the short, medium, and
long term.
b. The impact of climate-related risks and
opportunities on the organization’s businesses,
strategy, and financial planning.
c. The resilience of the organization’s strategy,
taking into consideration different climate-
related scenarios, including a 2°C or
lower scenario.
Our strategy to become an Integrated Energy
Company, and our net zero ambition and aims are
set out on pages 2-3, 15 and 49. In developing
this strategy, the board and leadership team
consider a wide range of opportunities and risks
across three discrete time horizons:
Short term (to 2025): the next five years are
defined by detailed business and financial
plans, which are performance managed in
delivery of our 2025 targets.
Medium term (to 2030): looking out 10 years
enables us to think beyond the short-term to
consider signposts and milestones towards the
longer-term scenarios, enabling us to adjust
course if required.
Long term (to 2050): recognizing the wide
range of uncertainties, we use a scenario
planning approach to help us explore possible
pathways for the energy transition over the
next 30 years, as the world moves towards net
zero. This includes consideration of changes in
policy, societal preferences, economic growth
and technological progress. For more detail on
our approach and how it informs our strategy,
see page 11.
54
bp Annual Report and Form 20-F 2020
Strategic report
As part of our annual planning process we review
the group’s principal risks and uncertainties.
Climate change and the transition to a lower
carbon economy has been identified as a
principal risk, see page 68. This covers various
aspects of how risks associated with the energy
transition could manifest. Similarly, physical
climate-related risks such as extreme weather
are covered in our principal risks related to
safety and operations.
Our processes for identifying, assessing,
managing and monitoring climate-related risks are
integrated into bp’s risk management policy and
the associated risk management procedures.
Examples of how physical and transition
climate-related risks are identified, assessed
and managed:
In the North Sea and Gulf of Mexico, regions
more prone to severe weather conditions, our
offshore facilities monitor meteorological and
oceanographic conditions through collection of
measurements at these facilities. These data
are collated and periodically compared against
the Basis of Design for the facility. If significant
differences are observed, then this may trigger
an update to the Basis of Design, prompting
action to re-assess risks such as structural
integrity and station-keeping and if necessary,
implement additional risk mitigations. Updates
may also occur as a result of other new
knowledge, analysis methods and data.
Transition risks are typically identified and
managed by business, regional or central
teams. For example, our strategy &
sustainability team has identified risks relating
to evolving policies across different regions.
They work with bp’s leadership as well as with
both central and regional legal teams,
communications & advocacy and external
advisors to manage and monitor these risks.
Metrics and targets
TCFD recommendation: Disclose the
metrics and targets used to assess and
manage relevant climate-related risks and
opportunities where such information
is material.
We present the principal group-wide metrics and
targets used to assess and manage climate-
related risks and opportunities below. This also
addresses the CA100+ resolution requirement to
disclose the company’s principal metrics and
relevant targets or goals consistent with the Paris
goals. We consider this to cover the principal
metrics used at group level to help monitor
progress on delivery of our strategic consistency
with the Paris goals – including our net zero aims.
In addition, we report on selected energy group
illustrative metrics«. A reference table of these
can be found at bp.com/sustainability.
Our group-wide principal metrics and relevant targets/goals
TCFD recommended disclosures Section of report
a. Disclose the metrics used
Our strategic focus areas,
including low carbon electricity
and energy and convenience
and mobility
Our financial frame: investing at
scale in the energy transition
Our investor proposition:
2021 guidance
Price assumptions
Investment criteria
Evaluating material new capex for
consistency with Paris goals
KPIs
Sustainability: water and
biodiversity metrics
Remuneration
Directors’ remuneration report
Incentivizing our employees to
advocate for net zero
Sustainability: GHG emissions
Sustainability: net zero aims
by the organization to assess
climate-related risks and
opportunities in line with
its strategy and risk
management process
b. Disclose Scope 1, Scope 2,
and, if appropriate, Scope 3
greenhouse gas (GHG)
emissions, and the
related risks.
c. Describe the targets used by
the organization to manage
climate-related risks and
opportunities and performance
against targets.
Where
2025, 2030, 2050 metrics, page 18 (in table).
Five aims to get to net zero, page 49 (in table).
Sector specific IRR hurdle rates for transition and low carbon
investments, page 22.
Balanced investment criteria, page 30.
Renewable power returns, page 22.
Total capital expenditure, page 23.
Key investment appraisal assumptions, page 28 (in table).
Carbon price (in table).
Investment economics, page 30.
Quantitative evaluations, page 31.
Investment economics: IRR and discounted payback.
Environment and sustainability: operational carbon intensity«.
Key performance indicators, page 39.
Managing our environmental impacts, page 56.
Director’s remuneration report, page 103.
2020 annual bonus outcome, page 110.
2021 remuneration policy on a page, page 124.
Aim 7, page 51.
SECR table, page 50.
Ratio of Scope 1 and 2 emissions: gross production, page 50.
TCFD: risk management, page 54.
Risk factors, page 67.
For further GHG metrics see bp.com/ESGdata
Aim 1-5 summary of 2020 performance, 2025 targets and 2030
aims, page 49.
Aim 1 performance (Scope 1 and 2), page 49.
Aim 2 performance (Scope 3), page 49.
Aim 3 performance (emissions from the carbon in our upstream
oil and gas production), page 50.
Aim 4 performance (methane) page 51.
bp Annual Report and Form 20-F 2020
55
Sustainability continued
Managing our
environmental impacts
Our health, safety, security and environmental
(HSSE) goals are: no accidents, no harm to
people and no damage to the environment.
We work hard to avoid, mitigate and manage
our environmental and social impacts over the
life of our operations.
The way our businesses around the world are
expected to understand and manage their
environmental and social impacts is set out
in our operating management system« (OMS).
This includes requirements on engaging with
stakeholders who may be affected by
our activities.
In planning our projects, we identify potential
impacts from our activities in areas such as land
rights, water use and protected areas. We use
the results of this analysis to identify actions and
mitigation measures and look to implement these
in project design, construction and operations.
Our OMS requires each of bp’s operating
businesses and functions to create and maintain
its own OMS handbook, describing how it will
carry out its local operating activities. Through
self-verification, local business processes are
reviewed and areas for improvement are
prioritized, allowing focus on delivering safe,
reliable and compliant operations.
Air emissions
We monitor our air emissions and put measures
in place to reduce the potential impact of our
activities on local communities. As part of our aim
19 we plan to evaluate the air emissions from our
global operating facilities to better understand
how they may be affected while advancing our
net zero aims for GHG emissions.
For more on air emissions, see the
bp Sustainability Report 2020.
Caring for our planet
Our sustainability frame includes a focus on
making a positive difference to the environment
in which we operate. The scope of our care for
our planet aims covers biodiversity, water
management, nature-based solutions including
those that reduce or remove carbon, circularity
and sustainable purchasing.
Water
We actively manage our freshwater demands in
areas of stress and scarcity. Based on analysis
using the World Resources Institute Aqueduct
Global Water Risk Atlas, four of our 24 major
operating sites were located in regions with high
or extremely high water stress in 2020, with
another four in areas of medium to high water
stress. This number reduces to three in regions
with high or extremely high water and three in
regions of medium to high water stress, if our
bp petrochemicals and other 2020 divestments
are excluded.
In 2020 we saw a 2% fall in freshwater
withdrawals and a 17% fall in freshwater
consumption compared to 2019. This was largely
due to the divestment of our Alaskan operation in
2020, the formation of the bp Bunge non-
operated joint venture from bp operated biofuels
and biopower businesses at the end of 2019 and
a reduction in freshwater use in our bpx energy
operations during 2020.
We have set an aim to be water positive by 2035.
We aim to replenish more freshwater than we
consume in our operations. We will do this by
being more efficient in operational freshwater use
and effluent management, and by collaborating
with others to replenish freshwater in stressed
and scarce catchment areas where we operate.
Biodiversity
We have set an aim to enhance biodiversity,
focusing on making a positive impact through
our actions to restore, maintain and enhance
biodiversity where we work.
We expect that from 2022 all new bp projects in
scope will have plans in place aiming to achieve
net positive impact (NPI), with a target for 90% of
actions to be delivered within five years of project
approvala. We also aim to enhance biodiversity at
our major operating sites and support biodiversity
restoration and sustainable use of natural
resource projects in the countries where we have
current or growing investments.
In 2020 we launched our new biodiversity
position and focused on sharing it with our
stakeholders and putting in place the resources
to deliver it. We also started work on defining
our NPI methodology with Fauna & Flora
International, which we expect to complete
at the end of 2021.
bp.com/biodiversity
Our aims to care for our planet:
Aim 16: enhance biodiversity.
Aim 17: water positive.
Aim 18: championing nature-based solutions.
Aim 19: unlock circularity.
Aim 20: sustainable purchasing.
bp.com/planet
a Applicable projects that have the potential for significant direct impacts on biodiversity. Only actions that are intended to be delivered within five years in accordance with the NPI methodology are
included. The 30% and 90% targets apply in aggregate across all applicable projects that meet the relevant timeframes from the final project approval (and are not targets for individual projects).
56
bp Annual Report and Form 20-F 2020
Strategic report
People and society
bp’s success depends on having
a talented and diverse workforce
that represents the communities
we serve.
Number of employees at 31 Decembera
Upstream
Downstream
Other businesses
and corporate
2020
2019
2018
13,700 16,600 16,900
42,700
41,300 44,300
8,600
9,200 13,400
Total
63,600
70,100 73,000
a Reported to the nearest 100. For more information see
Financial statements – Note 35.
Our people are the most important element of
our success. We need a motivated, engaged,
and diverse workforce to deliver our purpose
and strategy.
We promote a culture that generates the
diversity of thought, approach and ideas
needed to reimagine energy and move to
a low carbon environment.
The people and culture committee helps facilitate
the CEO’s oversight of people related matters. In
2020 the committee discussed key items,
including our remuneration policy, progress in our
diversity and inclusion programme, employee
engagement, workplace, our talent and learning
programmes and long-term people priorities. The
committee also spent significant time focusing
on the reinvent bp programme and related design
and selection activities.
Attraction and retention
We aim to recruit talented people from diverse
backgrounds, and invest in training, development
and competitive rewards for all our people. We
invest in employee development – with a focus
on driving safe, reliable and compliant operations,
and on building technical, functional and
leadership capability. This includes a range of
development opportunities for our people
through a mix of on-the-job learning,
developmental relationships with mentors,
managers and peers, and training delivered
face-to-face, virtually and through simulation
or e-learning.
Reinvent bp selection process
As part of our work to reinvent bp we are running
selection processes and considering in-scope
employees for roles within the new organizational
design, with the outcome that around 10,000
employees will leave bp by early 2022. The
selection processes focus on office-based
non-operational roles.
We have put robust steps in place to help ensure
that the selection processes are fair and objective
and that employees are supported before and
after receiving their selection outcome
confirmation.
We have appointed and coached neutral
observers to challenge selection decisions and
help mitigate unconscious bias and trained line
managers on how to undertake fair and
meritocratic selection decisions. Where roles are
impacted by the selection processes, bp adheres
to local laws.
Line managers were given supporting resources
for the notification process, including guides,
training and scripts on communicating outcomes
compassionately. We will continue to provide
these resources throughout the remaining
selection processes. Employees were provided
with supporting resources, including guidance on
preparing for change, mental wellbeing, preparing
for outcome conversations, and dealing with
uncertainty. Employees were encouraged to use
the Employee Assistance Programme
throughout.
We also established our myFuture programme,
which provides tools, resources and support to
help leavers navigate the next stage in their
career or phase of life.
See pages 36-37 for more on reinvent
bp and our new organizational model.
Diversity
Our mission is to create an environment in which
everyone can bring their best and true selves to
work, to reach their potential and support the
reinvention of bp.
Ethnic diversity
In 2020 we published our UK and US frameworks
for action to help combat racial injustice in bp.
Both frameworks have three key focus areas:
transparency, accountability and talent. Those
actions will include: publishing a comprehensive
global diversity & inclusion (D&I) report in 2021,
embedding expectations and metrics on D&I
delivery in our operating plans, reporting
externally on our UK ethnicity pay gap annually
and doubling our spend with US-based diverse
suppliers by 2023.
A total of 30% of our group leaders came from
countries other than the UK and the US in 2020
(2019 25%).
Gender equality
The gender balance across bp as a whole is
improving, with women representing 39% of bp’s
total population (2019 38%). 38% of our 120
newly-appointed extended leadership team are
women and our goal is to increase this.
At the end of 2020 we had five female directors
(2019 5) on our board. Our people and
governance committee remains mindful of
diversity when considering potential candidates.
For more information on the composition of our
board, see page 74.
Workforce by gender
As at
31 December 2020
Board directors
Leadership team
Group leaders
Subsidiary
directors
All employees
Male Female
Female
%
6
8
193
5
4
77
1,351
38,826
284
24,719
45
33
29
17
39
bp.com/ukgenderpaygap
Inclusion
To promote an inclusive culture we provide
leadership training and support employee-run
advocacy groups in areas such as gender,
ethnicity, sexual orientation and disability. As well
as bringing employees together, these groups
support our recruitment programmes and
provide feedback on the potential impact of
policy changes. Each group is sponsored
by a senior executive.
We aim to provide equal opportunity in
recruitment, career development, promotion,
training and reward for all employees – regardless
of ethnicity, national origin, religion, gender, age,
sexual orientation, marital status, disability, or any
other characteristic protected by applicable laws.
Where existing employees become disabled, our
policy is to engage and use reasonable
accommodations or adjustments to enable
continued employment.
Employee engagement
Our managers hold team and one-to-one
meetings with their team members,
complemented by formal processes through
works councils in parts of Europe. We regularly
communicate with employees on factors that
affect bp’s performance, and seek to maintain
constructive relationships with labour unions
formally representing our employees.
bp Annual Report and Form 20-F 2020
57
We incorporate the UN Guiding Principles on
Business and Human Rights, which set out
how companies should prevent, address and
remedy human rights impacts, into our
business processes.
When working to remediate any impacts on the
rights of local communities we are open to
co-operating in good faith to agree remedial
actions through state-led mechanisms such as
the Organisation for Economic Co-operation and
Development National Contact Points. We
recognize the importance of accessible and
effective operational-level grievance mechanisms
in addressing our impacts.
bp.com/humanrights
Our aims to improve people’s lives:
Aim 11: more clean energy.
Aim 12: just transition.
Aim 13: sustainable livelihoods.
Aim 14: greater equity.
Aim 15: enhance wellbeing.
bp.com/people
Sustainability continued
To understand what our employees think and feel
about bp, we run an annual ‘Pulse’ survey as well
as ‘Pulse Live’ surveys, which enable us to
monitor changes in employee sentiment on a
weekly basis. The overall employee engagement
positivity score in our 2020 annual survey was
64% (2019 65%). Pride in working for bp was
75% (2019 75%).
Employees participating in the 2020 Pulse survey
told us they strongly supported the launch of bp’s
new purpose and ambition in February and the
strategy announcement in August. Initial
positivity over the strategy waned in December,
with employees expressing anxiety about the
reinvent process and economic uncertainty
during 2020. Most participants felt confident in
bp’s approach to managing the impact of the
COVID-19 pandemic. Employees also told us we
should focus on addressing workload, supporting
health and wellbeing and being transparent about
the new structure.
Share ownership
We continue to encourage employee share
ownership and have a number of employee
share plans in place. For example, we operate
a ShareMatch plan in more than 50 countries,
matching bp shares purchased by our employees.
We also make annual share awards as part of our
total reward package all for senior and mid-level
employees globally, and a portion of our more
junior professional grade staff.
In February 2021, we introduced the reinvent bp
share award to incentivize our employees in
meeting our aims. All employees will receive a
one-off grant of either shares or share options
that will become available to keep, sell or transfer
in the first quarter of 2025.
Wellbeing and mental health
Mental health and physical wellbeing are priorities
for us and we recognized that the COVID-19
pandemic had direct and indirect consequences
for our employees and their families. We offered
access to a range of facilities and services,
including support through our well-established
Employee Assistance Programme and new
interventions, including providing access to
the Headspace app to both employees and
their partners.
Our annual global physical wellbeing programme
had 5,887 participants from 59 countries, with
positive feedback on helping keep teams
connected and keeping people physically active.
We continue to improve our systematic
management of health data points and sources,
to identify where we can target preventive
interventions and provide training, support and
resources to help improve employee wellbeing
and performance.
We believe wellbeing at work is becoming part
of the bp language – a critical part of caring
for our people and the communities in which
we operate.
Value to society
Improving people’s lives
One of our sustainability frame areas of focus
is to improve people’s lives. We have set five
people aims focusing on where bp can make
the biggest difference.
We want people to benefit from our presence
in their local communities, wherever we run
projects or operate.
This includes collaborating with local
communities to support sustainable livelihoods
and build greater resilience as part of a just
transition. Our work on sustainable livelihoods to
date supports several of the UN Sustainable
Development Goals, in particular on education,
health and economic growth as drivers for
sustainable livelihoods.
Human rights
We believe everyone deserves to be treated with
fairness, respect and dignity. At bp we strive to
conduct our business in a responsible way,
respecting the human rights of our workers and
everyone we come into contact with. Our human
rights policy and our code of conduct help us do
that. See page 63 for information on how we
updated our business and human rights policy
in 2020.
We respect internationally recognized human
rights as set out in the International Bill of Human
Rights and the International Labour Organization’s
Declaration on Fundamental Principles and Rights
at Work, including the core Conventions. These
include the rights of our workforce and those
living in communities potentially affected by
our activities.
58
bp Annual Report and Form 20-F 2020
Safety
Safety is our core value and
permeates everything we do. In
2020 it remained our first priority
throughout our transformation
process and the COVID-19
pandemic. Fundamentally, safety
is about caring for our employees
and the communities in which
we operate.
Process safety events
Number of incidents
100
84
80
60
40
20
0
61
56
16
18
16
72
26
53
17
2016
2017
2018
2019
2020
Tier 1
Tier 2
Recordable injury frequency
Workforce incidents per 200,000 hours worked
0.33
0.21
0.35
0.34
0.30
0.20
0.18
0.19
0.4
0.3
0.2
0.1
0
2016
2017
2018
2019
2020
Workforce
0.211
Employees 0.194
Contractors 0.222
0.218
0.202
0.229
0.198
0.152
0.233
0.166
0.128
0.193
0.132
0.094
0.163
American Petroleum
Institute US
benchmark*
International
Association of Oil
& Gas Producers
benchmark*
* API and OGP 2020 data reports not available until May 2021.
Strategic report
We have taken steps to help our employees
operate safely during the COVID-19 pandemic.
Tragically, we saw one fatality related to illness,
rather than a process safety incident, in our
operations in 2020. This occurred in December in
our Indonesian operations when an employee
died following COVID-19 infection contracted on
site. We deeply regret this loss and offer our
deepest condolences to the employee’s family.
See page 8 for more information.
Keeping people safe
All our employees and contractors have the
responsibility and the authority to stop unsafe
work. Our safety rules guide our workers on
staying safe while performing tasks with the
potential to cause most harm. The rules are
aligned with our operating management system
(OMS) and focus on areas such as working at
heights, lifting operations and driving safety. We
monitor and report on key workforce personal
safety metrics in line with industry standards.
We include both employees and contractors in
our data.
We have seen improvements in personal safety
in 2020 and while this may in part be a
consequence of decreased activity during the
COVID-19 pandemic, we also believe that other,
more intentional factors, are involved – namely
the groundwork we have done over the past few
years, including our deepening focus on safety
leadership, human performance, and the
effectiveness of our safety processes such as
permit-to-work.
Our recordable injury frequency, reduced from
0.166 in 2019 to 0.132 in 2020. There is always
more we can do, and we remain focused on
further improving our results.
Recordable injury
frequencya
Day away from
work case
frequencyb
Severe vehicle
accident rate
2020
2019
2018
0.132
0.166
0.198
0.044
0.047
0.048
0.01
0.05
0.04
a Incidents that result in a fatality or injury per 200,000
hours worked.
b Incidents that result in an injury where a person is unable
to work for a day (shift) or more per 200,000 hours worked.
bp Annual Report and Form 20-F 2020
59
Sustainability continued
Managing safety
bp-operated businesses are responsible for
identifying and managing operating risks and
bringing together people with the right skills and
competencies to address them. Our safety and
operational risk assurance team works alongside
bp-operated businesses to provide oversight and
technical guidance, while our group audit team
visits sites on a risk-prioritized basis to check how
they are managing risks.
Our operating management system
Our OMS is a group-wide framework designed
to help us manage risks in our operating activities
and drive performance improvements. It brings
together bp requirements on health, safety,
security, the environment, social responsibility
and operational reliability, as well as related
issues, such as maintenance, contractor relations
and organizational learning, into a common
management system. Our OMS also helps us
improve the quality of our activities by setting a
common framework that our operations must
work to. We review and amend these
requirements from time to time to reflect our
priorities. Any variations in the application of
our OMS, in order to meet local regulations or
circumstances, are subject to a governance
process. Recently acquired operations need
to transition to our OMS.
Preventing incidents
We carefully plan our operations, with the aim of
identifying potential hazards and having rigorous
operating and maintenance practices applied by
capable people to manage risks at every stage.
We design our new facilities in line with process
safety, good design and engineering principles.
We track our safety performance using industry
metrics such as the American Petroleum Institute
recommended practice 754 and the International
Association of Oil & Gas Producers
recommended practice 45.
Our process safety performance improved from
2019 and was roughly comparable to 2018 and
2017. There were 35% fewer tier 1 process
safety events in 2020 compared to 2019, but our
performance was broadly in line with the previous
three years. We also recorded 26% fewer tier 2
process safety events compared to 2019, lower
than the previous 10 years. The combined tier 1
and tier 2 process safety events were down 29%
in 2020 compared to 2019.
We investigate incidents including near misses.
And we use leading indicators, such as
inspections and equipment tests, to monitor
the strength of controls to prevent incidents.
60
bp Annual Report and Form 20-F 2020
Tier 1 and tier 2
process safety
eventsa
Oil spills –
numberb
Oil spills
contained
Oil spills reaching
land and water
Oil spilled –
volume
(thousand litres)
Oil unrecovered
(thousand litres)
2020
2019
2018
70
98
72
121
152
124
70
46
784
494
90
58
63
57
710
538
300
131
a Tier 1 process safety events are losses of primary containment
of greatest consequence – such as causing harm to a member
of the workforce, costly damage to equipment or exceeding
defined quantities. Tier 2 events are those of lesser
consequence.
b Number of spills greater than or equal to one barrel (159 litres,
42 US gallons).
Emergency preparedness
The scale and spread of bp’s operations means
we must be prepared to respond to a range of
possible disruptions and emergency events,
such as the COVID-19 pandemic. We maintain
disaster recovery, crisis and business continuity
management plans and work to build day-to-
day response capabilities to support local
management of incidents.
Security
We monitor for hostile actions that could harm
our people or disrupt our operations. These
actions might be connected to political or social
unrest, terrorism, armed conflict or criminal
activity. We take these potential threats seriously
and assess them continuously. Our 24-hour
response information centre in the UK uses
state-of-the-art technology to monitor evolving
high-risk situations in real time. It helps us to
assess the safety of our people and provide them
with practical advice if there is an emergency.
Cyber security
The severity, sophistication and scale of cyber
attacks continues to evolve. The increasing
digitalization and reliance on IT systems makes
managing cyber risk an even greater priority for
many industries, including our own. The risk
comes from a variety of cyber-threat actors,
including nation states, criminals, terrorists,
hacktivists and insiders. As with previous years,
we’ve experienced threats to the security of our
digital infrastructure, but none of these had a
significant impact on our business in 2020.
We have a range of measures to manage this
risk, including the use of cyber-security policies
and procedures, security protection tools,
continuous threat monitoring and event detection
capabilities, and incident response plans. We also
conduct exercises to test our response to and
recovery from cyber attacks. To encourage
vigilance among our staff, our cyber-security
training and awareness programme covers topics
such as phishing and the correct classification
and handling of our information. We collaborate
closely with governments, law enforcement and
industry peers to understand and respond to new
and emerging threats.
Working with contractors
Through documents that help bridge between
our policies and those of our contractors, we
define the way our safety management system
co-exists with those of our contractors to
manage risk on a site. For our contractors facing
the most serious risks, we conduct quality,
technical, health, safety and security audits
before awarding contracts. Once they start work,
we continue to monitor their safety performance.
Our OMS includes requirements and practices
for working with contractors. Our standard
model contracts include health, safety and
security requirements.
We expect and encourage our contractors and
their employees to act in a way that is consistent
with our code of conduct and take appropriate
action if those expectations, or their contractual
obligations, are not met.
Our partners in joint arrangements«
In joint arrangements where we are the operator,
our OMS, code of conduct and other policies
apply. We aim to report on aspects of our
business where we are the operator – as we
directly manage the performance of these
operations. We monitor performance and how
risk is managed in our joint arrangements,
whether we are the operator or not. Where we
are not the operator, our OMS is available as a
reference point for bp businesses when engaging
with operators and co-venturers. We have a
group framework to assess and manage bp’s
exposure related to safety, operational and
bribery and corruption risk from our participation
in these types of arrangements. Where
appropriate, we may seek to influence how risk
is managed in arrangements where we are not
the operator.
Strategic report
Tax transparency
We comply with tax laws in a responsible
manner, pay and report our taxes on time and
have open and constructive conversations with
stakeholders, including governments and tax
authorities. And we contribute to initiatives that
simplify and improve tax regimes to encourage
investment and sustainable growth and support
the energy transition. We are committed to being
transparent about our tax principles and the taxes
we pay.
We paid $3.3 billion in corporate income
and production taxes to governments (2019
$6.9 billion).
In 2020 we endorsed the B Team Responsible
Tax Principles and we published Our tax
report 2019.
The report provides more detailed information on
how we approach tax matters and the tax
payments we make. New disclosures in our tax
report include the total tax contribution for our
global operations. This covers: all our business
activities and details the taxes we pay directly to
governments on our own behalf, along with taxes
we collect and pay to governments on behalf of
others; financial and tax data from our OECD
country-by-country report, summary activities of
bp subsidiaries by country and details of bp
companies located in countries considered to be
low tax jurisdictions.
bp is a founding member of the Extractive
Industries Transparency Initiative (EITI), which
supports the disclosure of payments made to and
received by governments in relation to oil, gas
and mining. Through EITI we work with
governments, NGOs and international agencies
to improve transparency.
bp.com/tax
We provide training to employees appropriate to
the nature or location of their role. Around 7,700
employees completed anti-bribery and corruption
training in 2020 (2019 ~11,000). We assess any
exposure to bribery and corruption risk when
working with suppliers and business partners.
Where appropriate, we put in place a risk
mitigation plan or we reject them if we conclude
that risks are too high.
We also conduct anti-bribery compliance audits
on selected suppliers when contracts are in
place. Many of our production & operations
projects conduct supplier audits to assess their
conformance with our anti-bribery and corruption
contractual requirements. We take corrective
action with suppliers and business partners that
fail to meet our expectations, which may include
terminating contracts. In 2020 we issued 35 audit
reports (2019 25).
While our audit process was disrupted in 2020
due to the COVID-19 pandemic, we continued
to engage suppliers and communicate our
expectations for managing bribery and corruption
risk on behalf of bp. For example, our customers
& products business delivered a regional annual
contractor forum digitally, to provide awareness
of bribery and corruption risks.
Political donations and activity
We prohibit the use of bp funds or resources to
support any political candidate or party. We
recognize the rights of our employees to
participate in the political process and these
rights are governed by the applicable laws in the
countries where we operate. The way in which
we interact with those governments depends on
the legal and regulatory framework in each
country. Our stance on political activity is defined
in our code of conduct.
In the US we provide administrative support for
the bp employee political action committee
(PAC), which is a non-partisan committee that
encourages voluntary employee participation in
the political process. All bp employee PAC
contributions are reviewed for compliance with
federal and state law and are publicly reported in
accordance with US election laws. The PAC
paused all contributions for six months beginning
in January 2021. During this time the PAC will
re-evaluate its criteria for candidate support.
Business ethics
and accountability
Our values and code of conduct
Our values of safety, respect, excellence, courage
and one team represent the qualities and actions
we wish to see in bp. They inform how we do
business and the decisions we make. We use
these values as part of our recruitment,
promotion and individual performance
management processes.
Our code of conduct is based on our values and
sets clear expectations for how we work at bp.
It applies to all bp employees and members of
the board.
Employees, contractors or other third parties who
have a question about our code of conduct or see
something that they feel is unethical or unsafe
can discuss this with their managers, supporting
teams, works councils (where relevant) or
through OpenTalk, a confidential and anonymous
helpline operated by an independent company.
We received more than 1,600 concerns or
enquiries through these channels in 2020 (2019
1,800). The most commonly raised concerns
were related to the ‘Our people’ section of our
code of conduct. The section addresses issues
such as harassment, equal opportunity, and
diversity and inclusion. We take steps to identify
and correct areas of non-conformance and take
disciplinary action where appropriate. In 2020 our
businesses dismissed approximately 50 bp
employees for non-conformance with our code of
conduct or unethical behaviour (2019 82a). This
excludes dismissals of contractors and vendors,
and staff employed at our retail service stations.
Anti-bribery and corruption
We operate in parts of the world where bribery
and corruption present a high risk. We have a
responsibility to our employees, our shareholders
and the countries and communities in which
we do business to be ethical and lawful in all
our work.
Our code of conduct explicitly prohibits
engaging in bribery or corruption in any form.
Our group-wide anti-bribery and corruption policy
and procedures include measures and guidance
to assess risks, understand relevant laws
and report concerns. They apply to all
bp-operated businesses.
a 2019 figure differs from the 2019 figure (74) reported in the bp Annual Report and Form 20-F 2019 to reflect backdated dismissal
decisions (concerns where dismissals were not known or recorded until after the 2019 report was published), heliport spot check
dismissals and changes to dismissal decisions.
bp Annual Report and Form 20-F 2020
61
Sustainability continued
TCFD index table
Our expanded TCFD disclosures can be found on the following pages.
TCFD recommended disclosure
Governance
Disclose the organization’s
governance around climate-related
issues and opportunities.
Strategy
Disclose the actual and potential
impacts of climate-related risks and
opportunities on the organization’s
business, strategy and financial
planning where such information
is material.
Risk management
Disclose how the organization
identifies, assesses and manages
climate-related risks.
Metrics and targets
Disclose the metrics and targets
used to assess and manage relevant
climate-related risks and opportunities
where such information is material.
a. Describe the board’s oversight of climate-related
risks and opportunities.
Where reported
Page 52.
b. Describe the management’s role in assessing and
managing climate related risks and opportunities.
Page 53.
a. Describe the climate-related risks and
opportunities the organization has identified
over the short, medium, and long term.
b. Describe the impact of climate-related risks and
opportunities on the organization’s businesses,
strategy, and financial planning.
c. Describe the resilience of the organization’s
strategy, taking into consideration different
climate-related scenarios, including a 2°C or
lower scenario.
a. Describe the organization’s processes for
identifying and assessing climate-related risks.
b. Describe the organization’s processes for
managing climate-related risks.
c. Describe how processes for identifying, assessing,
and managing climate-related risks are integrated
into the organization’s overall risk management.
a. Disclose the metrics used by the organization
to assess climate-related risks and opportunities
in line with its strategy and risk management
process.
b. Disclose Scope 1, Scope 2, and, if appropriate,
Scope 3 GHG emissions, and the related risks.
c. Describe the targets used by the organization to
manage climate-related risks and opportunities
and performance against targets.
Pursuing a strategy that is consistent with the
Paris goals, pages 26-27.
Strategy – page 54.
Risk factors, pages 67-70.
Risk factors, pages 67-70 – description of principal risks.
Strategy – page 54.
Our strategy, page 15.
Pursuing a strategy that is consistent with the
Paris goals, pages 26-27.
Strategy – page 54.
Risk management – pages 54-55.
How we manage risk, pages 64-66.
Risk factors – page 67.
Risk management, pages 54-55.
How we manage risk, pages 64-66.
Risk management, pages 54-55.
How we manage risk, pages 64-66.
Risk factors – pages 67-70.
Our strategic focus areas and metrics, pages 18 and 19.
Our group-wide principal metrics and relevant targets
– page 55.
GHG emissions data – pages 49-50.
Our net zero targets and aims at a glance –
pages 49-51.
Sustainability at bp
More information on our sustainability reporting.
More information on our sustainability
performance bp.com/sustainability
Key environmental, social and governance
dataa bp.com/ESGdata
For our mapping to key sustainability frameworks
and standards, including SASB and GRI, see
bp.com/reportingcentre
a Selected sustainability information in the ESG datasheet was subject to limited assurance by Deloitte LLP in accordance with the
International Standard for Assurance Engagements (“ISAE”) 3000 (Revised).
62
bp Annual Report and Form 20-F 2020
Our stakeholders
How we engage with our stakeholders
Strategic report
Throughout bp we engage with a wide variety of stakeholders on a regular basis. This engagement
informs our thinking and decision making. Some examples of our engagement in 2020 are set out below.
Section 172 statement
In accordance with the requirements of section
172 of the Companies Act 2006 (‘the Act’), the
directors consider that, during the financial year
ended 31 December 2020, they have acted in
a way that they consider, in good faith, would
most likely promote the success of the company
for the benefit of its members as a whole, having
regard to the likely consequences of any decision
in the long term and the broader interests of other
stakeholders, as required by the Act.
See table on pages 82-83 for more
information in support of this statement,
including a description of the board’s
activities during 2020.
Employees
Monitoring employee sentiment
We use our ‘Pulse’ survey and weekly ‘Pulse
Live’ surveys to gather feedback from
employees, including their perceptions of work
demands and leadership support. The employee
engagement score is a key performance indicator
for bp, see page 41.
Responding to feedback
When our ‘Pulse Live’ and Employee
Assistance platforms showed increased
anxiety in employees, our CEO Bernard
Looney led a series of live webcasts, including
one focused on reducing mental health stigma
and encouraging employees to ask for help.
We also increased the frequency of mental
health awareness training for managers.
Keeping connected through webcasts
CEO Bernard Looney hosted regular ‘Keeping
Connected’ webcasts to discuss important topics
with members of the leadership team and
subject matter experts such as our partner
Equinor’s EVP, New Energy Solutions, and our
vice president health and wellbeing, Dr Richard
Heron. The sessions included a live Q&A
section where employees could ask questions,
anonymously if desired, of the CEO and
webcast guests.
See page 86 for more on how the board
and senior management team engaged
with stakeholders throughout the year.
Investors
Developing our new strategy, financial
frame and investor proposition
Our decision to introduce a new strategy,
financial frame and investor proposition, including
a new distribution policy, benefited from
extensive dialogue with our major shareholders.
ESG engagement
We engage frequently with our investors on
environmental, social and governance (ESG)
issues. This includes one-to-one conversations,
participation at external events and group
meetings, including with Climate Action 100+
representatives.
bp week
In response to feedback from investors and
others, CEO Bernard Looney and his leadership
team offered further insight into bp’s new
strategy and sustainability frame during bp week
– three consecutive virtual capital markets days
held in September 2020.
Society
Our biodiversity position
We developed our updated position with input
and constructive challenge from international
nature and conservation organizations and
experts including Conservation International,
Fauna & Flora International (FFI), UNESCO and
IUCN. The position sets out new measures to
help restore, maintain and enhance nature. In
September we announced a five-year
collaboration with FFI to help support the delivery
of our new position, including our aim to achieve
a net positive impact.
Our human rights policy
We updated our business and human rights
policy in 2020 to address emerging human rights
issues relevant to our industry, clarify our human
rights commitments and communicate how bp’s
approach to managing human rights impacts
has advanced. The update was supported by
consultations with a wide range of NGOs,
subject matter experts and investors.
Examples of engagement with other stakeholder groups
Customers
Collaboration with original equipment manufacturers such as Ford, Renault, JLR and Volvo
on future technologies.
Global customer brand tracking.
Government and regulators
Publication of Our tax report 2019 – see bp.com/tax.
Government lobbying – we actively advocated for regional carbon pricing schemes in the US,
provided input to the EU methane strategy and supported the UK government’s planned phase
out of internal combustion engines.
Partners and suppliers
Supplier workshops, including sessions focused on net zero, people and planet.
University collaborations, including the Carbon Mitigation Initiative (CMI), an independent
academic research programme based at Princeton University.
bp Annual Report and Form 20-F 2020
63
How we manage risk
How we manage risk
bp manages, monitors and reports on the principal
risks and uncertainties that can impact our ability to
deliver our strategy. These risks are described in the
Risk factors on page 67.
Our management systems, organizational structures, processes,
standards, code of conduct and behaviours together form a system
of internal control that governs how we conduct the business of bp
and manage associated risks.
bp’s risk management system
bp’s risk management system and policy is designed to be a consistent
and clear framework for managing and reporting risks from the group’s
operations to management and to the board. The system seeks to avoid
incidents and enhance business outcomes by allowing us to:
Understand the risk environment, identify the specific risks and assess
the potential exposure for bp.
Business and strategic risk management – our businesses, integrators
and enablers integrate risk management into key business processes such
as strategy, planning, performance management, resource and capital
allocation, and project appraisal. We do this by using a standard framework
for collating risk data, assessing risk management activities, making further
improvements and in connection with planning new activities.
Oversight and governance – throughout the year management, the
leadership team, the board and relevant committees provide oversight
of how significant risks to bp are identified, assessed and managed. They
help to ensure that risks are governed by relevant policies and are managed
appropriately. Such oversight may include reviews of the outcomes
of business processes including strategy, planning and resource and
capital allocation.
bp’s group risk team analyses the group’s risk profile and maintains
the group’s risk management system. Our internal audit team provides
independent assurance to the chief executive and board as to whether the
group’s system of internal control is adequately designed and operating
effectively to respond appropriately to the risks that are significant to bp.
Determine how best to deal with these risks to manage overall
potential exposure.
Risk oversight and governance
Manage the identified risks in appropriate ways.
Monitor and seek assurance of the effectiveness of the management
of these risks and intervene for improvement where necessary.
Report up the management chain and to the board on a periodic basis
on how significant risks are being managed, monitored, assured and
the improvements that are being made.
Key risk oversight and governance committees include the following:
Leadership team and its committees
Leadership team meeting – for oversight and for strategic and
commercial risks.
Group operations risk committee – for health, safety, security,
environment and operations integrity risks.
Day-to-day risk
management
Identify, manage
and report risks
Business and strategic
risk management
Oversight and
governance
Group financial risk committee – for finance, treasury, trading and
cyber risks.
Plan, manage
performance
and assure
Set policy and monitor
principal risks
Group disclosure committee – for financial reporting risks.
Group people and culture committee – for employee risks.
Facilities, assets
and operations
Businesses,
integrators and
enablers
Leadership team
and enablers
The board
Our risk management activities
Day-to-day risk management – management and staff at our facilities,
assets, and within our businesses, integrators and enablers seek to identify
and manage risk, promoting safe, compliant and reliable operations. bp
requirements, which take into account applicable laws and regulations,
underpin the practical plans developed to help reduce risk and deliver safe,
compliant and reliable operations as well as greater efficiency and
sustainable financial results.
Group ethics and compliance committee – for legal and regulatory
compliance and ethics risks.
Resource commitment meeting – for investment decision risks.
bp quarterly audit meeting – for assurance on the oversight of bp’s
principal risks.
Board and its committees
bp board.
Audit committee.
Safety and sustainability committee.
Remuneration committee.
People and governance committee.
For bp governance framework see page 88, Board activities
see page 80, committee reports see pages 92-102 and 105 and
Risk management and internal control see page 127.
64
bp Annual Report and Form 20-F 2020
Strategic report
Risk management processes
We aim for a consistent basis of measuring risk to:
Establish a common understanding of risks on a like-for-like basis,
taking into account potential impact and likelihood.
Report risks and their management to the appropriate levels of the
organization.
Inform prioritization of specific risk management activities and
resource allocation.
Businesses, integrators and enablers review significant risks and associated
risk management activities in alignment with key business processes to
help enable key decisions to be risk informed.
As part of bp’s annual planning process, the leadership team and board
review the group’s principal risks and uncertainties and determine risks
for particular oversight by the board and its committees. These may be
updated during the year in response to changes in internal and external
circumstances.
Our risk profile
The nature of our business operations is long term, resulting in many of
our risks being enduring in nature. Nonetheless, risks can develop and
evolve over time and their potential impact or likelihood may vary in
response to internal and external events. These may include emerging
risks which are considered through existing processes, including bp’s risk
management system, bp’s Energy Outlook, bp’s Technology Outlook and
group strategic reviews.
We identify longer-term strategic risks and high priority risks for particular
oversight by the board and its various committees in the coming year.
There can be no certainty that our risk management activities will mitigate
or prevent these, or other risks, from occurring. Further details of the
principal risks and uncertainties we face are set out in Risk factors
on page 67.
Risks for particular oversight by the
board and its committees in 2021
Climate-related risks
Risks associated with climate change and the transition to a lower
carbon economy impact many elements of our strategy and, as such,
these risks are considered through key business processes including
the strategy, annual plan, capital allocation and investment decisions.
The outputs of these key business processes are reviewed in line with
the cadence of these activities.
Further details are described in Climate change and the environment
on page 52.
Strategic and commercial risks
Financial liquidity
External market conditions can impact our financial performance.
Supply and demand and the prices achieved for our products can be
affected by a wide range of factors including political developments,
consumer preferences for low carbon energy, global economic
conditions and the influence of OPEC.
We seek to manage this risk through bp’s diversified portfolio, our
financial framework, liquidity stress testing, maintaining a significant
cash buffer, regular reviews of market conditions and our planning and
investment processes.
See Prices and markets and Liquidity, financial capacity and financial,
including credit, exposure on page 67.
The impact of COVID-19
The spread of COVID-19 has caused a significant drop in the oil and
gas prices and refining margins. bp’s future financial performance will
be impacted by the extent and duration of the current market conditions
and the effectiveness of the actions that it and others take, including
its financial interventions. Our financial frame is designed to be robust
to periods of low price, with flexibility to reduce cost and capital
expenditure if required. We continue to assess the impact of
COVID-19 on our staff and operations and have instigated appropriate
mitigation plans.
The risks for particular oversight by the board and its committees in
2021 have been reviewed and are listed in this section. These may be
updated throughout the year in response to changes in internal and external
circumstances. The oversight and management of other risks is undertaken
in the normal course of business. In addition to the risks reviewed in 2020,
climate-related risks remain a longer-term strategic risk.
Cyber security
The targeted and indiscriminate threats to the security of our digital
infrastructure and those of third parties continue to evolve rapidly and
are increasingly prevalent across industries worldwide. In addition, the
COVID-19 pandemic changed ways of working and introduced new
phishing campaigns.
We seek to manage this risk through a range of measures, which include
cyber security standards, security protection tools, ongoing detection
and monitoring of threats and testing of cyber response and recovery
procedures. We collaborate closely with governments, law enforcement
agencies and industry peers to understand and respond to new and
emerging cyber threats. We build awareness with our staff, share
information on incidents with leadership for continuous learning and conduct
regular exercises including with the leadership team to test response and
recovery procedures.
bp Annual Report and Form 20-F 2020
65
How we manage risk continued
Geopolitical
The diverse locations of our operations around the world expose us to
a wide range of political developments and consequent changes to the
economic and operating environment. Geopolitical risk is inherent to many
regions in which we operate, and heightened political or social tensions
or changes in key relationships could adversely affect the group.
We seek to manage this risk through development and maintenance of
relationships with governments and stakeholders and by becoming trusted
partners in each country and region. In addition, we closely monitor events
and implement risk mitigation plans where appropriate.
The impact of the UK’s exit from the EU
We have been assessing the potential impact on bp of Brexit and the
UK’s future global relationships and have not identified any significant
risk to our business.
Safety and operational risks
Process safety, personal safety and environmental risks
The nature of the group’s operating activities exposes us to a wide range
of significant health, safety and environmental risks such as incidents
associated with releases of hydrocarbons when drilling wells, operating
facilities and transporting hydrocarbons.
Our operating management system« helps us manage these risks
and drive performance improvements. It sets out the standards and
requirements which govern key risk management activities such as
inspection, maintenance, testing, business continuity and crisis response
planning and competency development. In addition, we conduct our drilling
activity through a wells organization in order to promote a consistent
approach for designing, constructing and managing wells.
Security
Hostile acts such as terrorism or piracy could harm our people and
disrupt our operations. We monitor for emerging threats and vulnerabilities
to manage our physical and information security.
Our central security team provides guidance and support to our
businesses through a network of regional security advisors who advise
and conduct assurance activities with respect to the management of
security risks affecting our people and operations. We continue to
monitor threats globally and maintain disaster recovery, crisis and
business continuity management plans.
Compliance and control risks
Ethical misconduct and legal or regulatory non-compliance
Ethical misconduct or breaches of applicable laws or regulations could
damage our reputation, result in litigation, regulatory action and penalties,
adversely affect results and shareholder value, and potentially affect our
licence to operate.
Our code of conduct and our values and behaviours, applicable to all
employees, are central to managing this risk. Additionally, we have
various group requirements and training covering areas such as anti-bribery
and corruption, anti-money laundering, competition/anti-trust law and
international trade regulations. We seek to keep abreast of new regulations
and legislation and plan our response to them. We offer an independent
confidential helpline, OpenTalk, for employees, contractors and other
third parties.
Trading non-compliance
In the normal course of business, we are subject to risks around our
trading activities which could arise from shortcomings or failures in our
systems, risk management methodology, internal control processes or
employee conduct.
We have specific operating standards and control processes to manage
these risks, including guidelines specific to trading, and seek to monitor
compliance through our dedicated compliance teams. We also seek to
maintain a positive and collaborative relationship with regulators and
the industry at large.
The impact of reinventing bp on the organization
Last year we announced that we are reinventing bp to help deliver
our ambition.
This significant reorganization includes a new structure, a new leadership
team, new ways of working and a reduction in the size of bp’s office-
based workforce. Risks associated with these changes have been
identified, assessed and are being managed. As part of our three lines of
defence, our businesses, integrators and enablers are working to deliver
clear accountabilities and the associated workload reduction. All
individuals changing roles or leaving bp are required to complete a
comprehensive management of change. Material risk management
actions are being assured by internal audit.
66
bp Annual Report and Form 20-F 2020
Strategic report
Major project delivery – failure to invest in the best opportunities or
deliver major projects successfully could adversely affect our financial
performance.
We face challenges in developing major projects, particularly in
geographically and technically challenging areas. Poor investment choice,
efficiency or delivery, or operational challenges at any major project that
underpins production or production growth could adversely affect our
financial performance.
Geopolitical – exposure to a range of political developments and
consequent changes to the operating and regulatory environment could
cause business disruption.
We operate and may seek new opportunities in countries, regions and
cities where political, economic and social transition may take place.
Political instability, changes to the regulatory environment or taxation,
international trade disputes and barriers to free trade, international
sanctions, expropriation or nationalization of property, civil strife, strikes,
insurrections, acts of terrorism, acts of war and public health situations
(including the continued impact of the COVID-19 pandemic or any future
epidemic or pandemic) may disrupt or curtail our operations or development
activities. These may in turn cause production to decline, limit our ability to
pursue new opportunities, affect the recoverability of our assets or cause us
to incur additional costs, particularly due to the long-term nature of many of
our projects and significant capital expenditure required. Events in or relating
to Russia, including trade restrictions and other sanctions, could adversely
impact our income and investment in or relating to Russia. Our ability to
pursue business objectives and to recognize production and reserves
relating to these investments could also be adversely impacted.
Liquidity, financial capacity and financial, including credit, exposure
– failure to work within our financial framework could impact our ability to
operate and result in financial loss.
Failure to accurately forecast or work within our financial framework
could impact our ability to operate and result in financial loss. Trade and
other receivables, including overdue receivables, may not be recovered,
divestments may not be successfully completed and a substantial and
unexpected cash call or funding request could disrupt our financial
framework or overwhelm our ability to meet our obligations.
Risk factors
The risks discussed below, separately or in combination, could have a
material adverse effect on the implementation of our strategy, our business,
financial performance, results of operations, cash flows, liquidity, prospects,
shareholder value and returns and reputation.
Strategic and commercial risks
Prices and markets – our financial performance is impacted by fluctuating
prices of oil, gas and refined products, technological change, exchange rate
fluctuations, and the general macroeconomic outlook.
Oil, gas and product prices are subject to international supply and demand
and margins can be volatile. Political developments, increased supply from
new oil and gas or alternative low carbon energy sources, technological
change, global economic conditions, public health situations (including
the continued impact of the COVID-19 pandemic or any future epidemic
or pandemic) and the influence of OPEC can impact supply and demand
and prices for our products. Decreases in oil, gas or product prices could
have an adverse effect on revenue, margins, profitability and cash flows.
If significant or for a prolonged period, we may have to write down assets
and re-assess the viability of certain projects, which may impact future
cash flows, profit, capital expenditure, the ability to work within our financial
frame and maintain our long-term investment programme. Conversely, an
increase in oil, gas and product prices may not improve margin performance
as there could be increased fiscal take, cost inflation and more onerous
terms for access to resources. The profitability of our refining activities can
be volatile, with periodic over-supply or supply tightness in regional markets
and fluctuations in demand.
Exchange rate fluctuations can create currency exposures and impact
underlying costs and revenues. Crude oil prices are generally set in US
dollars, while products vary in currency. Many of our major project«
development costs are denominated in local currencies, which may
be subject to fluctuations against the US dollar.
Access, renewal and reserves progression – inability to access, renew
and progress upstream resources in a timely manner could adversely affect
our long-term replacement of reserves.
Focused renewal of our reserve base in line with our strategy depends on
our ability to progress upstream resources from our existing portfolio and
access new resource in our core areas, generating future opportunities
for oil and natural gas production. Competition for access to investment
opportunities, heightened political and economic risks where we operate,
unsuccessful exploration activity, technical challenges and capital
commitments may adversely affect our reserve replacement. This, and
our ability to progress upstream resources at a level in line with our strategic
outlook for hydrocarbon production, could impact our future production
and financial performance.
bp Annual Report and Form 20-F 2020
67
Risk factors continued
An event such as a significant operational incident, legal proceedings
or a geopolitical event in an area where we have significant activities,
could reduce our financial liquidity and our credit ratings. Credit rating
downgrades could potentially increase financing costs and limit access
to financing or engagement in our trading activities on acceptable terms,
which could put pressure on the group’s liquidity.
bp’s credit rating downgrades could also trigger a requirement for the
company to review its funding arrangements with the bp pension trustees
and may cause other impacts on financial performance. In the event of
extended constraints on our ability to obtain financing, we could be required
to reduce capital expenditure or increase asset disposals in order to provide
additional liquidity. See Liquidity and capital resources on page 306 and
Financial statements – Note 29.
Joint arrangements and contractors – varying levels of control over
the standards, operations and compliance of our partners, contractors and
sub-contractors could result in legal liability and reputational damage.
We conduct many of our activities through joint arrangements«,
associates«or with contractors and sub-contractors where we may have
limited influence and control over the performance of such operations. Our
partners and contractors are responsible for the adequacy of the resources
and capabilities they bring to a project. If these are found to be lacking, there
may be financial, operational or safety exposures for bp. Should an incident
occur in an operation that bp participates in, our partners and contractors
may be unable or unwilling to fully compensate us against costs we may
incur on their behalf or on behalf of the arrangement. Where we do not
have operational control of a venture, we may still be pursued by regulators
or claimants in the event of an incident.
Digital infrastructure and cyber security – breach or failure of our or third
parties’ digital infrastructure or cyber security, including loss or misuse of
sensitive information could damage our operations, increase costs and
damage our reputation.
The energy industry is subject to fast-evolving risks from cyber threat
actors, including nation states, criminals, terrorists, hacktivists and insiders.
A breach or failure of our or third parties’ digital infrastructure – including
control systems – due to breaches of our cyber defences, or those of third
parties, negligence, intentional misconduct or other reasons, could seriously
disrupt our operations. This could result in the loss or misuse of data or
sensitive information, injury to people, disruption to our business, harm to
the environment or our assets, legal or regulatory breaches and legal liability.
Furthermore, the rapid detection of attempts to gain unauthorized access
to our digital infrastructure, often through the use of sophisticated and
co-ordinated means, is a challenge and any delay or failure to detect could
compound these potential harms. These could result in significant costs
including fines, cost of remediation or reputational consequences.
Climate change and the transition to a lower carbon economy
– developments in policy, law, regulation, technology and markets, including
societal and investor sentiment, related to the issue of climate change could
increase costs, constrain our operations and affect our business plans and
financial performance.
Laws, regulations, policies, obligations, government actions, social
attitudes and customer preferences relating to climate change and the
transition to a lower carbon economy, including the pace of change to any
of these factors, and also the pace of the transition itself, could have
adverse impacts on our business including on our access to and realization
of competitive opportunities in any of our strategic focus areas, a decline in
demand for, or constraints on our ability to sell certain products, constraints
on production and supply and access to new reserves, adverse litigation
and regulatory or litigation outcomes, increased costs from compliance
and increased provisions for environmental and legal liabilities.
Investor preferences and sentiment are influenced by environmental,
social and corporate governance (ESG) considerations including climate
change and the transition to a lower carbon economy. Changes in those
preferences and sentiment could affect our access to capital markets and
our attractiveness to potential investors, potentially resulting in reduced
access to financing, increased financing costs and impacts upon our
business plans and financial performance.
Technological improvements or innovations that support the transition
to a lower carbon economy, and customer preferences or regulatory
incentives that alter fuel or power choices, could impact demand for oil
and gas. Depending on the nature and speed of any such changes and
our response, these changes could increase costs, reduce our profitability,
reduce demand for certain products, limit our access to new opportunities,
require us to write down certain assets or curtail or cease certain
operations, and affect investor sentiment, our access to capital markets,
our competitiveness and financial performance.
Policy, legal regulatory, technological and market developments related
to climate change could also affect future price assumptions used in the
assessment of recoverability of asset carrying values including goodwill,
the judgement as to whether there is continued intent to develop
exploration and appraisal intangible assets, the timing of decommissioning
of assets and the useful economic lives of assets used for the calculation
of depreciation and amortization. See Financial statements – Note 1 and
Climate change and the environment on page 52.
68
bp Annual Report and Form 20-F 2020
Strategic report
Such events or conditions, including a marine incident, or inability to
provide safe environments for our workforce and the public while at our
facilities, premises or during transportation, could lead to injuries, loss of
life or environmental damage. As a result we could face regulatory action
and legal liability, including penalties and remediation obligations, increased
costs and potentially denial of our licence to operate. Our activities are
sometimes conducted in hazardous, remote or environmentally sensitive
locations, where the consequences of such events or conditions could
be greater than in other locations.
Drilling and production – challenging operational environments and
other uncertainties could impact drilling and production activities.
Our activities require high levels of investment and are sometimes
conducted in challenging environments such as those prone to natural
disasters and extreme weather, which heightens the risks of technical
integrity failure. The physical characteristics of an oil or natural gas field,
and cost of drilling, completing or operating wells is often uncertain.
We may be required to curtail, delay or cancel drilling operations or stop
production because of a variety of factors, including unexpected drilling
conditions, pressure or irregularities in geological formations, equipment
failures or accidents, adverse weather conditions and compliance with
governmental requirements.
Security – hostile acts against our staff and activities could cause harm
to people and disrupt our operations.
Acts of terrorism, piracy, sabotage and similar activities directed against
our operations and facilities, pipelines, transportation or digital infrastructure
could cause harm to people and severely disrupt operations. Our activities
could also be severely affected by conflict, civil strife or political unrest.
Product quality – supplying customers with off-specification products
could damage our reputation, lead to regulatory action and legal liability,
and impact our financial performance.
Failure to meet product quality specifications could cause harm to people
and the environment, damage our reputation, result in regulatory action
and legal liability, and impact financial performance.
bp Annual Report and Form 20-F 2020
69
Competition – inability to remain efficient, maintain a high-quality portfolio
of assets, innovate and retain an appropriately skilled workforce could
negatively impact delivery of our strategy in a highly competitive market.
Our strategic progress and performance could be impeded if we are unable
to control our development and operating costs and margins, if we fail to
scale our businesses at pace, or to sustain, develop and operate a high-
quality portfolio of assets efficiently. Furthermore, as we transition from
an International Oil Company to an Integrated Energy Company, we face
an expanded and rapidly evolving range of competitors in the sectors in
which we operate. We could be adversely affected if competitors offer
superior terms for access rights or licences, or if our innovation in areas
such as new low carbon technologies, digital, customer offer, exploration,
production, refining, manufacturing or renewable energy lags those of our
competitors. Our performance could also be negatively impacted if we fail
to protect our intellectual property. Our industry faces increasing challenges
to recruit and retain diverse, skilled and experienced talent. Successful
recruitment, development and retention of specialist staff is essential
to our plans.
Crisis management and business continuity – failure to address
an incident effectively could potentially disrupt our business.
Our business activities could be disrupted if we do not respond, or are
perceived not to respond, in an appropriate manner to any major crisis
or if we are not able to restore or replace critical operational capacity.
Insurance – our insurance strategy could expose the group to
material uninsured losses.
bp generally purchases insurance only in situations where this is legally
and contractually required. Some risks are insured with third parties and
reinsured by group insurance companies. Uninsured losses could have a
material adverse effect on our financial position, particularly if they arise
at a time when we are facing material costs as a result of a significant
operational event which could put pressure on our liquidity and cash flows.
Safety and operational risks
Process safety, personal safety, and environmental risks – exposure to
a wide range of health, safety, security and environmental risks could cause
harm to people, the environment and our assets and result in regulatory
action, legal liability, business interruption, increased costs, damage to our
reputation and potentially denial of our licence to operate.
Technical integrity failure, natural disasters, extreme weather or a change
in its frequency or severity, human error and other adverse events or
conditions, including breach of digital security, could lead to loss of
containment of hydrocarbons or other hazardous materials. This could also
lead to constrained availability of resources used in our operating activities,
as well as fires, explosions or other personal and process safety incidents,
including when drilling wells, operating facilities and those associated with
transportation by road, sea or pipeline. There can be no certainty that our
operating management systemor other policies and procedures will
adequately identify all process safety, personal safety and environmental
risks or that all our operating activities, including acquired businesses, will
be conducted in conformance with these systems. See Safety on page 59.
Risk factors continued
Compliance and control risks
Ethical misconduct and non-compliance – ethical misconduct or
breaches of applicable laws by our businesses or our employees could
be damaging to our reputation, and could result in litigation, regulatory
action and penalties.
Incidents of ethical misconduct or non-compliance with applicable laws
and regulations, including anti-bribery and corruption and anti-fraud laws,
trade restrictions or other sanctions, could damage our reputation, and
result in litigation, regulatory action, penalties and potentially affect our
licence to operate.
Regulation – changes in the law and regulation could increase costs,
constrain our operations and affect our business plans and financial
performance.
Our businesses and operations are subject to the laws and regulations
applicable in each country, state or other regional or local area in which
they occur. These laws and regulations result in an often complex, uncertain
and changing legal and regulatory environment for our global businesses
and operations. Changes in laws or regulations, including how they are
interpreted and enforced, can and does impact all aspects of our business.
Royalties and taxes, particularly those applied to our hydrocarbon activities,
tend to be high compared with those imposed on similar commercial
activities. In certain jurisdictions there is also a degree of uncertainty
relating to tax law interpretation and changes. Governments may change
their fiscal and regulatory frameworks in response to public pressure on
finances, resulting in increased amounts payable to them or their agencies.
Changes in law or regulation could increase the compliance and litigation
risk and costs, reduce our profitability, reduce demand for or constrain
our ability to sell certain products, limit our access to new opportunities,
require us to divest or write down certain assets or curtail or cease certain
operations, or affect the adequacy of our provisions for pensions, tax,
decommissioning, environmental and legal liabilities. Changes in laws
or regulations could result in the nationalization, expropriation, cancellation,
non-renewal or renegotiation of our interests, assets and related rights.
Potential changes to pension or financial market regulation could also impact
funding requirements of the group. Following the Gulf of Mexico oil spill,
we may be subjected to a higher level of fines or penalties imposed in
relation to any alleged breaches of laws or regulations, which could result
in increased costs. See Regulation of the group’s business on page 321.
70
bp Annual Report and Form 20-F 2020
Treasury and trading activities – ineffective oversight of treasury and
trading activities could lead to business disruption, financial loss, regulatory
intervention or damage to our reputation.
We are subject to operational risk around our treasury and trading activities
in financial and commodity markets, some of which are regulated. Failure
to process, manage and monitor a large number of complex transactions
across many markets and currencies while complying with all regulatory
requirements could hinder profitable trading opportunities. There is a risk
that a single trader or a group of traders could act outside of our delegations
and controls, leading to regulatory intervention and resulting in financial loss,
fines and potentially damaging our reputation. See Financial statements –
Note 29.
Reporting – failure to accurately report our data could lead to regulatory
action, legal liability and reputational damage.
External reporting of financial and non-financial data, including reserves
estimates, relies on the integrity of the control environment, our systems
and people operating them. Failure to report data accurately and in
compliance with applicable standards could result in regulatory action,
legal liability and damage to our reputation.
The Strategic report was approved by the board and signed on its behalf by
Ben J. S. Mathews, company secretary, on 22 March 2021.
Corporate governance
Corporate governance
Introduction from the chairman
Board of directors
Leadership team
Board activities
Decision making by the board
How the board has engaged with shareholders,
the workforce and other stakeholders
Governance framework
Learning, development and induction
Board evaluation
People and governance committee
Audit committee
Safety and sustainability committee
Geopolitical committee
Directors’ remuneration report
Remuneration committee
Directors’ statements
72
74
78
80
82
86
88
90
91
92
94
100
102
103
105
127
Since 2017 when the partnership with bp began,
Lightsource bp has more than doubled its global
presence, from five to 14 countries. It’s also grown
its development pipeline from 1.6 to 17GW.
bp Annual Report and Form 20-F 2020
71
Introduction from the chairman
New strategy
As a board, our responsibilities include
determining bp’s purpose and strategy,
monitoring its culture and seeking assurance that
these are aligned with our values. For bp, 2020
was a year in which we felt this responsibility
especially keenly. With the board’s support, bp
adopted a new purpose – reimagining energy
for people and our planet, which aligns bp’s
capabilities and aspirations with the needs
of society.
2020 was also the year bp’s new CEO, Bernard
Looney, commenced his role. As well as
formally launching our new purpose, Bernard
set out a net zero ambition, new strategy,
financial frame and investor proposition. These
actions were taken with the full support of the
board following a process of careful debate, and
the board is confident that they respect bp’s
culture and values.
The change that was immediately most
consequential for many people within bp
was a restructure that will see close to 10,000
colleagues leave bp. It was difficult saying
goodbye to people who helped make our
organization what it is today – and the board
was united with the leadership team in
determining that the process should be
conducted fairly and respectfully.
That process is now largely complete, and
I believe, as does the board, that bp is now
leaner, flatter and nimbler – better able to
fulfil our new purpose, ambition and strategy.
COVID impact on working of the board
Change on this scale would be challenging in any
company at any time. So, I want to pay tribute to
my board colleagues for their contribution during
such a difficult period. It is to their credit that we
very quickly adapted to a new way of working
together – with our many meetings since March
held entirely virtually.
Indeed, the COVID-19 pandemic justified more
regular meetings with bp’s leadership – so early
in the pandemic we instituted weekly calls to
keep abreast of bp’s response to the pandemic
and how the team was taking account of the
needs and expectations of all our stakeholders.
Maintaining bp’s culture
Since joining bp, I have always been impressed
at the strength of the company’s culture – open,
co-operative, collaborative and performance-
focused. Rather than weaken that culture, I
believe that the pandemic has strengthened it
further – and has proved its value. bp would not
have achieved all it did in 2020 without such a
strong culture. We have been careful that the
changes introduced throughout the year are
respectful of it, and consistent with bp’s values
of safety, respect, excellence, courage and
one team.
Board composition
In 2020 we welcomed Tushar Morzaria, Karen
Richardson and Johannes Teyssen to the board.
They each have skills, experience and a diverse
mindset that is closely aligned to the strategic
direction we have set for bp.
We also said goodbye to friends who have
served bp with distinction over many years
– Nils Andersen, Brian Gilvary, Sir Ian Davis,
Dame Alison Carnwath and, of course, Bob
Dudley. bp has been fortunate to have them,
and we will miss them.
I was delighted that Paula Reynolds agreed
to take over from Sir Ian Davis as senior
independent director following the AGM 2020,
and that Melody Meyer was able to take over
the important role of chairing the safety and
sustainability committee after Nils Andersen
stepped down from the board. Tushar Morzaria
will take over as chair of the audit committee
after the AGM in May, following an extensive
handover from Brendan Nelson, who will
then retire.
2020 tested bp’s governance
processes like no other year.
Board members, like many
colleagues across bp, have
achieved and learned a lot
together through our new
way of working – and there’s
much that we will continue.
I am grateful for the flexibility,
commitment and clear-
sightedness of my board
colleagues in 2020 – it bodes
well for the years ahead.
Helge Lund
Chairman
72
bp Annual Report and Form 20-F 2020
In the coming year, one of my priorities will be
to ensure that the board remains at an appropriate
size, with strong composition, and with diversity
of both thought and skills in support of the
strategic direction we have set.
Diversity
The process of reinventing bp provided
opportunities to enhance bp’s diversity in other
ways, too. Though we have more to do in all
areas, we have made particular progress on
gender diversity at senior levels. In 2020, we
increased female board representation from
42% to 45%; increased female executive
committee representation from 15% to 31%;
and met the Hampton-Alexander and Parker
review targets for 2021.
New governance framework
To complement bp’s new strategic direction,
we have introduced a new governance
framework, covering bp’s board-level corporate
governance and facilitating a stronger board
focus on strategy, performance, people and
governance, with the committees each playing
a critical role in support. The emphasis on
strategy and its execution is especially important
– I believe it to be where the board can deliver
most value at this time, encouraging and working
closely with the leadership team as they drive
forward our strategic progress, safety, financial
and operational performance.
The governance framework redefines the
committees’ roles. Our newly-titled safety
and sustainability committee rightly gains an
enhanced focus on sustainability, but with no
let-up on our core and overriding priority – safety,
while our people and governance committee
gains an enhanced focus on our single most
important asset – our people. These committees
and the insights they provide to the board very
much support its effectiveness.
Conclusion
2020 tested bp’s governance processes like no
other year. Board members, like many colleagues
across bp, have achieved and learned a lot
together through our new way of working –
and there’s much that we will continue. I am
grateful for the flexibility, commitment and
clear-sightedness of my board colleagues in
2020 – it bodes well for the years ahead.
Helge Lund,
Chairman
22 March 2021
Corporate governance
Compliance with the UK Corporate
Governance Code
Throughout 2020, bp applied the principles
and complied with all the provisions of the
2018 UK Corporate Governance Code.
bp Annual Report and Form 20-F 2020
73
Board of directors
As at 22 March 2021
P
Helge Lund
Chairman
Appointed
Bernard Looney
Chief executive officer
Appointed
Board: 26 July 2018; Chairman: 1 January 2019
5 February 2020
Nationality
Norwegian
Outside interests
Nationality
Irish
Outside interests
Chairman of Novo Nordisk AS; Operating Advisor
to Clayton Dubilier & Rice; Member of the Board of
Trustees of the International Crisis Group; Member
of the European Round Table of Industrialists
Fellow of the Royal Academy of Engineering;
Fellow of the Energy Institute; Mentor for the
FTSE 100 Cross-Company Mentoring Executive
Programme; Non-executive director of Rosneft
Career summary
Career summary
Bernard Looney was appointed chief executive officer
in February 2020. He previously ran bp’s Upstream
business from April 2016 and has been a member of
the company’s executive management team since
November 2010. As chief executive, Upstream, Bernard
was responsible for bp’s oil and gas exploration,
development and production activities worldwide. In this
role, Bernard oversaw improvements in both process and
personal safety performances, and production grew by
20%. He led access into new countries, high-graded the
portfolio and created innovative new business models. In
earlier Upstream executive roles, he was responsible for
all bp-operated oil and gas production worldwide and for
all bp’s drilling and major project« activity. Bernard joined
bp in 1991 as a drilling engineer and worked in operational
roles in the North Sea, Vietnam and the Gulf of Mexico.
Skills and experience
Bernard has spent his career at bp and has demonstrated
dynamic leadership and vision as he has progressed
through various roles within bp. During his 10 years
as a leader of Upstream, Bernard saw the segment
through one of the most difficult periods in bp’s
history, helping transform the organization into a
safer, stronger and more resilient business. He was
instrumental in a number of workforce-based initiatives
to promote a diverse and inclusive environment.
Bernard set out bp’s new strategy in 2020 and is
guiding the company through its transformation.
Helge Lund was appointed chairman of the bp board
on 1 January 2019. He served as chief executive of BG
Group from 2015 to 2016, when it merged with Shell.
He joined BG Group from Equinor (formerly Statoil)
where he served as its president and chief executive
officer for 10 years from 2004. Prior to Equinor, Helge
was president and chief executive officer of the
industrial conglomerate Aker Kvaerner, and has also
held executive positions in the Norwegian industrial
holding company, Aker RGI, and the former Norwegian
power and industry company, Hafslund Nycomed. He
worked as a consultant with McKinsey & Company
and served as a political advisor for the parliamentary
group of the Conservative party in Norway. Prior to
joining bp, he was a non-executive director of the oil
service group Schlumberger from 2016 to 2018, and
Nokia from 2011 to 2014. He served as a member
of the United Nations Secretary-General’s Advisory
Group on Sustainable Energy from 2011 to 2014.
Skills and experience
Helge’s distinguished career as a leader in the oil and
gas industry and his open-minded and forward-looking
approach is vital as he leads the board in its oversight
of delivery of bp’s new strategy. He has deep industry
knowledge and global business experience – not only
in the oil and gas industry but also in pharmaceuticals,
healthcare and construction. His innovative leadership
of the board drives cohesion and a strong environment
for constructive challenge and oversight as bp works
to transform into an Integrated Energy Company.
Committee membership key
Chairman
A Audit committee
S Safety and sustainability committee
R Remuneration committee
P People and governance committee
74
bp Annual Report and Form 20-F 2020
Murray Auchincloss
Chief financial officer
Appointed
1 July 2020
Nationality
Canadian
Outside interests
Board member of Aker BP ASA; Member of
The 100 Group Main Committee
Career summary
Murray Auchincloss qualified as a chartered financial
analyst in the US, leading on to a wide range of tax
and financial roles, first for Amoco and then for bp
after the two organizations merged in 1998. Murray
has worked in both the US and UK, in a range of
roles including chief financial officer, Upstream,
and chief financial officer, North Sea. He was
commercial director for the North American Gas
business and, as head of the chief executive’s office
for three years, managed all aspects of that office.
Skills and experience
Murray’s financial expertise, experience and knowledge
make him a trusted advisor and bp group leader. His
broad experience of working across the group has
provided him with deep insight into bp’s assets and
businesses. Murray has a degree in commerce from
the University of Calgary, Canada, and qualified as a
chartered financial analyst at the University of West
Virginia, US. His drive to modernize is improving bp’s
financial teams, controlling costs and continuing to deliver
transparent financial disclosures to investors and markets.
Board gender diversity
1.
2.
1. Male
2. Female
7
5
Corporate governance
A R
S
S R
Pamela Daley
Independent non-executive director
Professor Dame Ann Dowling
Independent non-executive director
Melody Meyer
Independent non-executive director
Appointed
26 July 2018
Nationality
American
Outside interests
Appointed
3 February 2012
Nationality
British
Outside interests
Director of BlackRock, Inc.; Director of SecureWorks, Inc.
Career summary
Pamela Daley joined General Electric Company (GE)
in 1989 as tax counsel and held a number of senior
executive roles in the company, overseeing a wide range
of corporate transactions and serving as senior vice
president and senior advisor to the chairman in 2013,
before retiring from GE. Pamela has served as a director
of BlackRock since 2014 and of SecureWorks since
2016. She was a director of BG Group plc from 2014
to 2016 until its acquisition by Shell. She was a director
of Patheon N.V. from 2016 to 2017 until its acquisition
by Thermo Fisher and, prior to that, she was a partner
at Morgan, Lewis & Bockius, a major US law firm,
where she specialized in domestic and cross-border
tax-oriented financings and commercial transactions.
Skills and experience
Pamela is a qualified lawyer with significant management
insight obtained from previous senior positions
held at companies that operate in highly regulated
industries. Pamela has a wealth of experience in global
business and strategy gained from over 20 years
in an executive role at GE. She also has experience
in the UK oil and gas industry from her time served
on the BG Group plc board. Pamela contributes
important insight to the audit committee from her
previous executive experience. In 2019, she joined the
remuneration committee, where her understanding
of employee and investor perspectives brings value.
Deputy vice-chancellor and emeritus professor of
Mechanical Engineering at the University of Cambridge;
Non-executive director of Smiths Group plc
Career summary
Professor Dame Ann Dowling is a deputy vice-chancellor
and emeritus professor of mechanical engineering
at the University of Cambridge where her research
includes fluid mechanics, acoustics and combustion.
She has held visiting posts at MIT and at Caltech. Dame
Ann is a fellow of the Royal Society and the Royal
Academy of Engineering and a foreign associate of
the US National Academy of Engineering, the Chinese
Academy of Engineering and the French Academy of
Sciences. She was an advisor at Rolls-Royce until 2015.
Dame Ann was President of the Royal Academy of
Engineering from September 2014 to 2019. In December
2015 she was appointed to the Order of Merit.
Skills and experience
Professor Dame Ann is an internationally respected
leader in engineering research and the practical
application of new technology in industry. Her
contribution in these fields has been widely recognized
by universities around the world. Her academic
background provides valuable balance to the board
and brings a different perspective to the safety and
sustainability committee of which she is a member,
particularly as developments in technology continue to
accelerate. Her work in this area is supplemented by her
chairing the company’s technology advisory council.
Non executive directors’ tenure
Board nationality
1.
1.
4.
3.
1. <1 year
2. 1–3 years
3. 4–6 years
4. 7+ years
2.
3.
2.
3
3
2
2
1. UK
2. US
3. Non UK/US
4
4
4
Appointed
17 May 2017
Nationality
American
Outside interests
President of Melody Meyer Energy LLC; Director
of the National Bureau of Asian Research; Trustee
of Trinity University; Non-executive director of
AbbVie Inc.; Non-executive director of NOV, Inc.
Career summary
Melody Meyer started her career in 1979 with Gulf Oil
which later merged with Chevron Corporation, where
she remained until her retirement in 2016. During her
career with Chevron, Melody held several key leadership
roles in global exploration and production, working
on a number of international projects and operational
assignments. Melody was the executive sponsor of
the Chevron Women’s Network and continues as a
mentor and advocate for the advancement of women
in the industry. Melody is a C200 member, and has
received several awards and accolades throughout
her career including being recognized as a 2009 Trinity
Distinguished Alumni, with the BioHouston Women
in Science Award by Hart Energy as an Influential
Woman in Energy in 2018, by Women Inc as 2018 Most
Influential Corporate Board Directors, and Outstanding
Director by 2020 Women on Boards. She serves on
McKinsey Women in Energy Advisory Board and
co-leads Women Corporate Directors in Houston.
Skills and experience
Melody brings a world-class operational perspective
to the board, with a deep understanding of the
factors influencing safe, efficient and commercially
high-performing projects in a global organization.
Her long and illustrious career in the oil and gas
industry is predicated on a dedication to excellence,
safety and performance improvements. She has
expertise in the execution of major capital projects,
technology, R&D, creation of businesses in new
countries, strategic and business planning, merger
integration and safe and reliable operations.
bp Annual Report and Form 20-F 2020
75
Board of directors continued
As at 22 March 2021
A R
A P R
Tushar Morzaria
Independent non-executive director
Brendan Nelson
Independent non-executive director
Karen Richardson
Independent non-executive director
Appointed
1 September 2020
Nationality
British
Outside interests
Appointed
8 November 2010
Nationality
British
Outside interests
Group Finance Director of Barclays PLC; Member
of The 100 Group Main Committee; Chair of the
Sterling Risk Free Reference Rates Working Group
Non-executive director of NatWest Markets plc
Career summary
Career summary
Tushar Morzaria is a chartered accountant with over 25
years of strategic financial management, investment
banking, operational and regulatory relations experience.
He is currently Group Finance Director of Barclays PLC,
the British universal banking and financial services
company, where he is a member of the Barclays board
and executive committee. Tushar joined Barclays from
JP Morgan in 2013, where he held various senior roles
including the CFO of its Corporate & Investment Bank
at the time of the merger of the investment bank and
the wholesale treasury/security services business.
Skills and experience
Tushar’s position as Group Finance Director of Barclays
PLC gives him a breadth of knowledge and insight into
financial, tax, treasury, investor relations and strategic
matters which will benefit bp as Tushar assumes
the role of audit committee chair at the conclusion
of bp’s annual general meeting on 12 May 2021. He
has strong experience in delivering corporate change
programmes while maintaining a focus on performance.
Brendan Nelson is a qualified chartered accountant. He
was made a partner of KPMG in 1984. He served as a
member of the UK board of KPMG from 2000 to 2006,
subsequently being appointed vice chairman until his
retirement in 2010. At KPMG International he held a
number of senior positions including global chairman,
banking and global chairman, financial services. Brendan
has extensive financial experience, having been a
non-executive director of The Royal Bank of Scotland
Group p.l.c, where he also served as chairman of the
group audit committee, until April 2019 and National
Westminster Bank p.l.c. until December 2018.
Brendan previously served as a member of the
Financial Services Practitioner Panel for six years and
was chairman of the audit committee of the Institute
of Chartered Accountants of Scotland from 2005 to
2008 and later became President of the Institute of
Chartered Accountants of Scotland from 2013 to 2014.
Skills and experience
Brendan has completed a wide variety of audit,
regulatory and due-diligence engagements over the
course of his career. He played a significant role in
the development of the profession’s approach to the
audit of banks in the UK, with particular emphasis
on establishing auditing standards. His role as a
member of the Financial Reporting Review Panel
enabled him to further contribute to the profession.
This wide experience makes him ideally suited to
chair the audit committee and to act as its financial
expert. He brings related input from his role as the
chair of the audit committee of a major bank. His
specialism in the financial services industry allows
him to contribute insight into the challenges faced
by global businesses by regulatory frameworks.
As previously announced, Brendan will retire
from the board at the conclusion of bp’s
annual general meeting on 12 May 2021.
Appointed
1 January 2021
Nationality
American
Outside interests
Director of Artius Acquisition Inc.;
Director of Exponent Inc.
Career summary
Karen Richardson was Vice President of Sales at
Netscape Communications Corporation from 1995 to
1998 before embarking on several senior executive
roles at E.piphany from 1998 to 2003 and was Chief
Executive Officer between 2003 and 2006. In 2011
she became a non-executive director of BT plc where
she served for seven years and between 2016 and
2019 Karen was a director of Worldpay Inc. (Worldpay
Group plc). Karen is currently a director of Artius
Acquisition Inc., a special purpose acquisition company,
and, since 2013, Exponent Inc., the engineering and
scientific consulting company. Karen has a Bachelor
of Science degree in Industrial Engineering from
Stanford University and was awarded distinctions
from the Stanford Industrial Engineering Department
and the American Institute of Industrial Engineers.
Skills and experience
Karen has over 30 years’ experience in the technology
industry. She brings exceptional knowledge of digital,
technology, cyber and IT security matters from her
career working with innovative companies in Silicon
Valley. As bp works to transform into an Integrated
Energy Company, Karen has the skills, experience
and diversity to further enhance the board’s ability to
support and oversee the delivery of bp’s strategy.
From the conclusion of the 2021 annual general
meeting, Karen will become a member of the
audit committee.
76
bp Annual Report and Form 20-F 2020
Corporate governance
R A P
S P
S
Paula Rosput Reynolds
Senior independent director
Sir John Sawers
Independent non-executive director
Dr Johannes Teyssen
Independent non-executive director
Appointed
Appointed
Board: 14 May 2015; Senior independent: 27 May 2020
14 May 2015
Nationality
American
Outside interests
Nationality
British
Outside interests
Appointed
1 January 2021
Nationality
German
Outside interests
Non-executive director and Chair Designate of National
Grid plc; Non-executive director of General Electric
Company; Chair of the Seattle Cancer Care Alliance
Career summary
Paula Rosput Reynolds commenced her energy career
at Pacific Gas & Electric Corp in 1979 and spent over 25
years in the energy industry. She has held a number of
executive positions during her career, including CEO of
Duke Energy Power Services, Chairman, President and
CEO of AGL Resources as well as Chairman and CEO
of Safeco Corporation and Vice Chairman and Chief
Restructuring Officer of AIG. Paula was a non-executive
director of TransCanada Corporation and CBRE Group,
Inc until May 2019, having been appointed in 2011 and
2016 respectively. Between 2011 and 2020 Paula was
a non-executive director of BAE Systems PLC. Paula
was awarded the National Association of Corporate
Directors (US) Lifetime Achievement Award in 2014.
Skills and experience
Paula has had a long career leading global companies
in the energy and financial sectors. Her experience
with international and US companies, including several
restructuring processes and mergers, gives her
insight into strategic and regulatory issues, which is
an asset to the board. Her wider business experience
and understanding of the views of investors are well
suited to her being the chair of bp’s remuneration
committee and senior independent director.
Visiting Professor at King’s College London; Senior
Adviser at Chatham House; Senior Fellow at the
Royal United Services Institute; Global Adviser at the
Council on Foreign Relations; Governor of the Ditchley
Foundation; Director of the Bilderberg Association, UK;
Executive Chairman of Newbridge Advisory Limited
Career summary
Sir John Sawers spent 36 years in public service
in the UK, working on foreign policy, international
security and intelligence. He was chief of the Secret
Intelligence Service, MI6, from 2009 to 2014 and prior
to that spent the bulk of his career in the Diplomatic
Service, representing the British government around
the world and leading negotiations at the UN, in the
European Union and in the G8. After he left public
service, Sir John was chairman and general partner of
Macro Advisory Partners, a firm that advises clients
on the intersection of policy, politics and markets
from February 2015 to May 2019. He then set up his
own firm, Newbridge Advisory, to carry out similar
work. Sir John was appointed Knight Grand Cross of
the Order of St Michael and St George in the 2015
New Year Honours for services to national security.
Skills and experience
Sir John’s deep experience of international political and
commercial matters is an asset to the board in navigating
the geopolitical issues faced by a modern global
company. Sir John’s unique skill set made him an ideal
chair of bp’s geopolitical committee and he will continue
to advise the board on these matters as the chair of
the newly established geopolitical advisory council.
CEO and Chairman of the management board of E.ON
SE (until 31 March 2021); Chairman of the Supervisory
Board of Innogy SE.; Member of the Shareholders’
Committee of Nord Stream AG; Member of the
Presidential Board of the Federation of German Industries
Career summary
Johannes began his professional career at VEBA AG in
1989. There he held a number of leadership positions
across Legal Affairs and Key Account Sales. In 2000
VEBA became part of E.ON and in 2001 Johannes
became a member of the Board of Management of
the E.ON Group’s central management company in
Munich. In 2004, he was also appointed to the Board of
Management of E.ON SE in Düsseldorf and later went
on to become Vice Chairman in 2008 and CEO in 2010.
He was President of Eurelectric from 2013 to 2015
and the World Energy Council’s Vice Chair responsible
for Europe between 2006 to 2012. Johannes was a
member of the Supervisory Board of Deutsche Bank AG
between 2008 and 2018 and is currently a member of the
Presidential Board of the Federation of German Industries
and the Shareholders’ Committee of Nord Stream AG.
Skills and experience
Johannes brings exceptional experience and
deep knowledge in the sector and its continuing
transformation. His skill set further diversifies and
strengthens the overall demographic and attributes
of the board as a whole. His experience in the energy
sector further enhances the board’s ability to support
and oversee the delivery of bp’s new strategy. Johannes
has a doctorate in law from the University of Göttingen.
Ben J S Mathews
Company secretary
Appointed
7 May 2019
Ben joined bp as a company secretary in May 2019. He is chairman
of the Association of General Counsel and Company Secretaries of
the FTSE 100 (GC100) and the co-chair of the Corporate Governance
Council of the Conference Board. Ben is also a Fellow of the Institute of
Chartered Secretaries and Administrators. Former appointments include
Group Company Secretary of HSBC Holdings plc and Rio Tinto plc.
bp Annual Report and Form 20-F 2020
77
Leadership team
As at 22 March 2021
The leadership team
represents the principal
executive leadership
of the bp group. Its
members include
bp’s executive directors
(Bernard Looney and
Murray Auchincloss
whose biographies
appear on page 74) and
the senior management
listed on these pages.
78
bp Annual Report and Form 20-F 2020
Emma Delaney
EVP, customers & products
Leadership team tenure
Appointed 1 July 2020
Emma previously served on bp’s executive team
starting on 1 April 2020.
Nationality
Irish
Other board memberships
None
Career
Emma has spent 25 years working in bp, both in the
Upstream and the Downstream, most recently as interim
chief executive officer Downstream from 1 April 2020
and prior to that as regional president for West Africa. She
has held a variety of senior roles including Upstream chief
financial officer for Asia Pacific and head of business
development for gas value chains. In Downstream she
held roles in retail and commercial fuels and planning.
William Lin
EVP, regions, cities & solutions
Leadership team tenure
Appointed 1 July 2020
Nationality
American
Other board memberships
William is a non-executive director of Pan American
Energy Group that operates in Argentina.
Career
William served as chief operating officer, Upstream
regions before joining the leadership team. He has
worked in bp for 25 years having spent most of his
career working abroad in different countries. Previous
senior roles include vice president – gas development
and operations for Egypt, regional president for Asia
Pacific and head of the group chief executive’s office.
William managed the successful start-up of the
Tangguh LNG facility during his time in Indonesia.
Geoff Morrell
EVP, communications & advocacy
Leadership team tenure
Appointed 1 July 2020
Nationality
American
Other board memberships
None
Career
Geoff moved to London in 2017 to take over group
communications and external affairs. He spent the
prior six years leading bp America’s communications
and government relations teams and was instrumental
in rebuilding bp’s reputation following the Deepwater
Horizon incident. Before joining bp, Geoff spent four years
at the Pentagon, serving as chief spokesperson for the
US Department of Defense under presidents Bush and
Obama. He previously worked as a journalist, including
as a White House correspondent for ABC News.
Corporate governance
Dev Sanyal
EVP, gas & low carbon energy
David Eyton
EVP, innovation & engineering
Leadership team tenure
Appointed 1 July 2020
Leadership team tenure
Appointed 1 July 2020
Gordon Birrell
EVP, production & operations
Leadership team tenure
Appointed 1 July 2020
Dev previously served on bp’s executive team
starting on 1 January 2012.
David previously served on bp’s executive team
starting on 1 September 2018.
Gordon previously served on bp’s executive team
starting on 12 February 2020.
Nationality
British and Indian
Nationality
British
Nationality
British
Other board memberships
Other board memberships
Other board memberships
Dev is a non-executive director of Man Group plc, a
member of the board of overseers of The Fletcher School
of Law and Diplomacy at Tufts University and a member
of the energy advisory board of the Government of India.
Career
Dev has been a member of the executive team since
2011, firstly as executive vice president, strategy and
regions, and since 2016, as chief executive alternative
energy and executive vice president, regions. Dev
joined bp in 1989 and has worked in London, Athens,
Istanbul, Vienna and Dubai across various segments.
Previous senior roles include CEO of bp Eastern
Mediterranean, CEO of Air bp and group treasurer. He
played a key role in bp navigating its way through the
aftermath of the 2010 Deepwater Horizon incident.
None
Career
None
Career
David joined the executive team in 2018 as group head
of technology. He joined bp in 1982 with a degree in
engineering and has held several positions in petroleum
engineering, commercial and business management.
Previous senior roles include managing Wytch
Farm, Trinidad Gas and Gulf of Mexico Deepwater
Developments. He was awarded a CBE (Commander
of the British Empire) by Queen Elizabeth II for his
contributions to UK engineering and energy. David is
a Fellow of the UK Royal Academy of Engineering.
Before being appointed to his new role, Gordon was
chief operating officer for production, transformation
and carbon. In his bp career, Gordon has spent
time in various leadership, technical, safety and
operational risk roles, including four years as bp
president Azerbaijan, Georgia and Turkey. Gordon is
a Fellow of the UK Royal Academy of Engineering.
Carol Howle
EVP, trading & shipping
Leadership team tenure
Appointed 1 July 2020
Nationality
British
Giulia Chierchia
EVP, strategy & sustainability
Leadership team tenure
Appointed 1 July 2020
Nationality
Belgian and Italian
Other board memberships
Other board memberships
None
Career
None
Career
Before taking on her current role, Carol ran bp Shipping
and was the chief operating officer for IST oil. She has
more than 20 years’ experience in the energy industry,
many in integrated supply and trading. Previous roles
include chief operating officer for natural gas liquids,
regional leader of global oil Europe and finance. Carol also
served as the head of the group chief executive’s office.
Giulia joined bp from McKinsey, where she was a
senior partner. She led the global downstream oil and
gas practice and was a key member of the chemicals
and electricity, power and natural gas practices. She
begins this role with more than 10 years’ experience
in the energy sector, including helping companies
shape their strategies for the energy transition.
Kerry Dryburgh
EVP, people & culture
Leadership team tenure
Appointed 1 July 2020
Nationality
British
Other board memberships
Kerry sits as a non-executive director for the
United Kingdom Strategic Command
Career
Kerry was previously head of HR for the Upstream and
has held a series of senior HR positions. She was a
key driver behind the Upstream people transformation
during 2015-2017. Kerry previously ran HR in bp’s
Shipping, IST and corporate functions teams. She brings
experience from other sectors in Europe and Asia, having
worked at both BT and Honeywell before joining bp.
Eric Nitcher
EVP, legal
Leadership team tenure
Appointed 1 July 2020
Eric previously served on bp’s executive team
starting on 1 January 2017.
Nationality
American
Other board memberships
None
Career
Eric sat on the executive team as group general
counsel from 2017. He played a key role in forming the
Russian joint venture TNK-BP and settling Deepwater
Horizon claims. He began his career as a litigation
and regulatory lawyer in Wichita, Kansas. He joined
Amoco in 1990 and over the years has held a wide
variety of roles, both in the US and elsewhere.
bp Annual Report and Form 20-F 2020
79
bp’s success is dependent upon effective and entrepreneurial
leadership by the board, establishing its purpose, strategy and values
and doing so within a framework of prudent and effective controls,
which enable risks to be assessed and managed. The board is
responsible to bp’s owners for promoting the long-term sustainable
success of the company, generating value for its shareholders, while
having regard to its other stakeholders, the impact of its operations
on the communities within which it operates, and the environment.
Primary tasks of the board in 2020 included
Defining and establishing a new purpose and strategy, while
assessing and monitoring whether they were consistent with
bp’s culture and values.
In light of the significant operational challenges presented by the
COVID-19 pandemic, establishing a rhythm of board meetings to
ensure that the leadership team was supported, providing guidance
to the CEO to ensure that shareholder and other stakeholder
interests were taken into account, while maintaining safe and
reliable operations.
Monitoring the activities and performance of bp’s leadership team,
obtaining assurance about the delivery of 2025 and 2030 targets
and aims and the sustainability frame within which they operate.
Designing and establishing the board’s new corporate governance
framework, including the delegations of authority under which
it operates.
Assessing and monitoring the principal risks and emerging risks of
bp, having considered feedback from the committees of the board.
Ways of working
New ways of working were put in place during 2020 alongside the changes to the design of the
board’s corporate governance framework. Meeting agendas were structured along four distinct
pillars: strategy, performance, people, and governance, with the overarching focus being on the
development of bp’s new strategy in support of its transition to an Integrated Energy Company.
The board and its committees met regularly during the year, as well as on an ad hoc basis, as
required by business needs. Attendance is shown in the table on page 84. Although the board and its
committees were able to hold physical meetings in the early part of the year, once COVID-19-related
restrictions and controls were introduced, most meetings took place virtually. Throughout the year,
the board and its committees continued to engage effectively through the use of technology. Key
areas covered during 2020 under each of these pillars are set out on the next page.
Corporate governance
Board activities
Role of the board
80
bp Annual Report and Form 20-F 2020
Strategy
During 2020 the board worked closely with the
incoming chief executive officer (CEO) and his
leadership team, establishing a new purpose
and strategy for bp. bp’s purpose is to reimagine
energy for people and our planet, with an
ambition to become a net zero company by
2050 or sooner, and to help the world get to
net zero. This new purpose recognizes:
The world is on an unsustainable path
– its carbon budget is running out.
Energy markets have begun to shift towards
low carbon and renewables.
Oil and gas produced safely and efficiently will
continue to perform a vital role for the world
and our business, but over the longer term,
demand for both oil and gas will be challenged.
bp can contribute to the energy transition
the world wants and needs and create value
in doing so.
The delivery and execution of the strategy that
supports this new purpose is made possible
through a resilient financial framework, including
a new approach to capital allocation. In 2020 the
board determined a new distribution policy, which
will support us in facing an increasingly uncertain
world, allow us to strengthen the balance sheet,
invest in our resilient and valuable hydrocarbons
business, and invest adequately into the energy
transition. A new distribution policy was approved
by the board, comprising a reset and resilient
dividend and a firm share buyback commitment,
see page 22.
Associated with the new strategy, the board
also agreed a number of tactical divestments,
including the disposal of its petrochemicals
business. Alongside this, new business
opportunities were progressed, for example
the formation of a strategic partnership with
Equinor, to develop offshore wind energy in
the US, see page 21.
Against the backdrop of the board’s activities
during 2020 described in this section, the table
on pages 82 and 83 sets out some examples
of board decision making in 2020 and how
the directors have performed their duty
under Section 172.
Performance
The board reviewed project, operational and
safety performance throughout the year, as
well as the latest view on full-year delivery
against plan and the implications for the group’s
scorecard measures. Equally, in light of the
challenging macro-economic environment facing
the sector, the company’s financial performance,
liquidity, credit position and associated financial
risks were closely and regularly monitored by
the board. In this way and through the regular
interactions that were taking place during the
year, the board was able to satisfy itself that
bp was performing while transforming.
Reports supplementing the role played by
the board included:
CEO and chief financial officer (CFO) reports.
Group financial outlook.
The annual effectiveness of investment review.
Quarterly and full-year results.
Shareholder distributions.
The annual plan and associated capital
allocation commitments.
On risk oversight, the board, assisted by its
committees, also regularly reviewed its principal
and emerging risks, including the process
through which they are identified, evaluated and
managed. Linked to this, the high-priority risks
were reviewed in 2020, giving the directors the
chance to seek assurance as to how those risks
were prioritized and being managed.
On internal controls, the board also assessed
the effectiveness of the group’s system of
internal control and risk management as part
of the process through which it reviews and,
ultimately, approves the bp Annual Report and
Form 20-F. No specific areas of significant
deterioration were identified in this assessment.
The board concluded that the group’s system
of internal control continued to be resilient. The
board also concluded that the overall design of
the group’s system of internal control generally
meets external expectations of components to
be included in internal control frameworks. In
arriving at these conclusions, the board took
into account reports from group risk and internal
audit, as well as reviews undertaken by the board
and its committees during the year. In conducting
reviews during the year, the board and its
committees considered the impact of remote
working on the control environment, among
other key factors.
For more information on bp’s system of risk
management see How we manage risk on page
64. Information about bp’s system of internal
control is on page 127.
Corporate governance
People
The board, through the former nomination and
governance committee, continued to focus on
reviewing its own composition, skills, experience
and diversity, as well as that of the bp leadership
team. Ultimately, new board appointments were
made during the year, most notably with the
retirement of the CEO, Bob Dudley, and CFO,
Brian Gilvary, succeeded by Bernard Looney
and Murray Auchincloss, respectively.
Tushar Morzaria was appointed to the board
and its audit committee with effect from
September 2020. Karen Richardson and
Dr Johannes Teyssen were appointed to the
board with effect from 1 January 2021.
Johannes was also appointed to the safety and
sustainability committee with effect from the
same date. A new leadership team under the
CEO came into being on 1 July 2020.
Through the new people and governance
committee, the process for executive succession
planning, talent management and development
is being redesigned. People insights – particularly
the reinvention of bp and its impact on the
organization – were presented to the board and
this committee by the CEO and EVP, people &
culture, providing information on matters relating
to people strategy, employee engagement,
diversity and people processes and policies.
To help inform board discussions and decisions,
board members also engaged directly with the
workforce in structured events, see page 87.
Governance
The board established a new corporate
governance framework, which is more closely
aligned with bp’s new purpose and also
reinforces the effectiveness of the internal control
framework. For more information on the new
corporate governance framework see page 88.
bp Annual Report and Form 20-F 2020
81
Corporate governance continued
Decision making by the board
The board delegates authority
for the executive management
of bp to the chief executive
officer, subject to defined limits.
Ultimately, the board retains
responsibility for – and regularly
monitors – the execution of this
delegation of authority, taking
action to update it as required.
As part of the wider board corporate governance
redesign, the board reviewed the delegation of
authority, in part reflecting the need to ensure
that it remained appropriate in light of bp’s new
strategy, and the 2025 and 2030 targets and
aims. The board’s new ways of working are
explained on page 80 including certain matters
that under the new corporate governance
framework are reserved for the board as set
out in its new terms of reference.
The execution of company strategy is undertaken
by the CEO’s leadership team, under the
day-to-day authority for the management of the
company delegated to the CEO. Reflecting
its governance responsibilities, the board satisfies
itself that the CEO and the leadership team’s
actions are in keeping with the direction it sets
through receipt of management reports at each
board meeting.
Matters reserved for the
board and section 172
Issue faced and decision taken
Establishing a new purpose
and strategy for bp
The board approved a new purpose for bp –
reimagining energy for people and our planet
– and a strategy to transition to an Integrated
Energy Company and to meet the net zero
ambition set out alongside bp’s purpose.
Section 172(1)a) to (f) matters considered, including
stakeholder group(s) affected and feedback received
How the board had regard to the
feedback in its decision making
Workforce
In town halls and leadership meetings employees wanted to know how bp
could do more to step up to the climate challenge and help society deal with
these issues. It became clear that employees were seeking even stronger
commitments to the climate change agenda by the company.
Community and environment
We consulted with communities, NGOs, academics and industry
associations – even bringing some of bp’s harshest critics into discussions
about the future of the company, about environment, social and governance
matters and the issues facing the world, drawing on their external expertise,
input and challenge.
Investors
We talked with investors about their expectations of bp and heard of their
desire for bp to continue to deliver operational excellence, to drive higher
returns but also to set out a clear medium to long-term vision for a
sustainable bp business in light of the energy transition.
Fostering business relationships
We received feedback from customers via the bp leadership team,
conveying the importance of being able to react rapidly to changing demand.
All the elements highlighted in Section 172 were central to the discussions
as the board evaluated the purpose and strategy options – what are bp’s
beliefs and what does bp want to be? The discussions encompassed bp’s
role with respect to its shareholders, employees and society. It considered
the value creation opportunities and the importance of leaning into the
changing needs of customer demand for convenience and society’s
demand for renewables and lower carbon energy.
The change in purpose and strategy reflects bp’s people’s belief that
we can create long-term value by helping solve one of society’s biggest
problems – climate change.
The decision was made with the long-term future and sustainability
of bp in mind with clear 2025 targets, 2030 aims and a 2050 goal.
More information on how the board had regard to the Section 172 factors
Section 172 factor
Key examples
The likely consequences of any
decision in the long term.
Interests of employees.
Fostering the company's business
relationships with suppliers,
customers and others.
Reinventing bp: Our strategy
How the board has engaged with shareholders,
the workforce and other stakeholders
Sustainability: People and society
How we engage with our stakeholders
Sustainability: Business ethics and accountability
Impact of operations on the
community and the environment.
Managing our environmental impacts
Sustainability: Safety
Maintaining a reputation for high
standards of business conduct.
Role of the board
Sustainability: Business ethics and accountability
Acting fairly between members of
the company.
How the board has engaged with shareholders,
the workforce and other stakeholders
Page
15
86
57
63
61
57
59-60
80
61
86
Reinvent bp
The board approved a reorganization of bp,
retiring the existing model and replacing it
with one that is more focused, more integrated
and faces the energy transition head on.
The reorganization will ultimately see around
10,000 employees leave bp.
The board considered the importance of skills evaluation to the delivery
The board supported the reinvention of bp, with the associated headcount
of cost reduction and the wider long-term strategic delivery of bp’s aims.
reduction that this implied.
They heard feedback from the CEO’s ‘Keeping Connected’ webcasts
Given the feedback received, although the board considered it was the
with the workforce together with responses to bp’s ‘Pulse’ surveys.
right decision to go ahead, they sought assurances from the executive that:
Considerations
The wider society context following the impact of COVID-19 and the
wider oil industry job losses.
The importance of putting the safety of employees first.
Companies should try to provide job assurance and consider the mental
health impact of job insecurity.
bp’s reputation for high standards of conduct and the importance
of honesty, fairness, and respect in the process.
The redundancy process was fair, transparent and objective with an
environment of honesty, trust and co-operation that put the care and
wellbeing of our people at the heart of the process.
The reduction in the workforce was conducted in a manner which
protected bp’s safe and reliable operations.
Support for the life transition that redundancy brings is offered
to the relevant employees.
Discretionary enhanced redundancy terms could be offered.
Financial frame and
distribution policy
The board approved a new and resilient
financial framework, including a coherent
approach to capital allocation and a new
distribution policy.
In considering the proposed financial frame and distribution policy,
the board had regard to:
The resilience of bp’s balance sheet for the long term.
Delivering sustainable value to shareholders.
The need for bp to invest adequately in the energy transition and low
carbon, to support the new ambition and strategy.
In approving the new distribution policy the directors reflected that there
may be some change in bp’s investor base as some investors focus
more on the short-term direct return that the dividend provides.
After considering all the various factors, the board concluded that a
resilient dividend intended to remain fixed at 5.25 cents per ordinary
share per quarter (subject to the board’s decision each quarter), with
a commitment to return at least 60% of surplus cash« to shareholders
through share buybacks (having reached $35 billion net debt« and
subject to maintaining a strong investment grade credit rating), was in
the best interest of the company, its shareholders as a whole and other
stakeholder groups, as it enabled bp to offer sustainable value with
increased investment in low carbon and non-oil and gas ventures.
82
bp Annual Report and Form 20-F 2020
Corporate governance
Issue faced and decision taken
Establishing a new purpose
and strategy for bp
The board approved a new purpose for bp –
reimagining energy for people and our planet
– and a strategy to transition to an Integrated
Energy Company and to meet the net zero
ambition set out alongside bp’s purpose.
In the context of the board’s activities during 2020, the table below sets out some examples of board decision
making in 2020 and how the directors have performed their duty under Section 172.
Section 172(1)a) to (f) matters considered, including
stakeholder group(s) affected and feedback received
How the board had regard to the
feedback in its decision making
Workforce
In town halls and leadership meetings employees wanted to know how bp
could do more to step up to the climate challenge and help society deal with
these issues. It became clear that employees were seeking even stronger
commitments to the climate change agenda by the company.
Community and environment
We consulted with communities, NGOs, academics and industry
associations – even bringing some of bp’s harshest critics into discussions
about the future of the company, about environment, social and governance
matters and the issues facing the world, drawing on their external expertise,
input and challenge.
Investors
We talked with investors about their expectations of bp and heard of their
desire for bp to continue to deliver operational excellence, to drive higher
returns but also to set out a clear medium to long-term vision for a
sustainable bp business in light of the energy transition.
Fostering business relationships
We received feedback from customers via the bp leadership team,
conveying the importance of being able to react rapidly to changing demand.
All the elements highlighted in Section 172 were central to the discussions
as the board evaluated the purpose and strategy options – what are bp’s
beliefs and what does bp want to be? The discussions encompassed bp’s
role with respect to its shareholders, employees and society. It considered
the value creation opportunities and the importance of leaning into the
changing needs of customer demand for convenience and society’s
demand for renewables and lower carbon energy.
The change in purpose and strategy reflects bp’s people’s belief that
we can create long-term value by helping solve one of society’s biggest
problems – climate change.
The decision was made with the long-term future and sustainability
of bp in mind with clear 2025 targets, 2030 aims and a 2050 goal.
Reinvent bp
The board approved a reorganization of bp,
retiring the existing model and replacing it
with one that is more focused, more integrated
and faces the energy transition head on.
The reorganization will ultimately see around
10,000 employees leave bp.
The board considered the importance of skills evaluation to the delivery
of cost reduction and the wider long-term strategic delivery of bp’s aims.
The board supported the reinvention of bp, with the associated headcount
reduction that this implied.
They heard feedback from the CEO’s ‘Keeping Connected’ webcasts
with the workforce together with responses to bp’s ‘Pulse’ surveys.
Given the feedback received, although the board considered it was the
right decision to go ahead, they sought assurances from the executive that:
Considerations
The wider society context following the impact of COVID-19 and the
wider oil industry job losses.
The importance of putting the safety of employees first.
Companies should try to provide job assurance and consider the mental
health impact of job insecurity.
bp’s reputation for high standards of conduct and the importance
of honesty, fairness, and respect in the process.
The redundancy process was fair, transparent and objective with an
environment of honesty, trust and co-operation that put the care and
wellbeing of our people at the heart of the process.
The reduction in the workforce was conducted in a manner which
protected bp’s safe and reliable operations.
Support for the life transition that redundancy brings is offered
to the relevant employees.
Discretionary enhanced redundancy terms could be offered.
Financial frame and
distribution policy
The board approved a new and resilient
financial framework, including a coherent
approach to capital allocation and a new
distribution policy.
In considering the proposed financial frame and distribution policy,
the board had regard to:
The resilience of bp’s balance sheet for the long term.
Delivering sustainable value to shareholders.
The need for bp to invest adequately in the energy transition and low
carbon, to support the new ambition and strategy.
In approving the new distribution policy the directors reflected that there
may be some change in bp’s investor base as some investors focus
more on the short-term direct return that the dividend provides.
After considering all the various factors, the board concluded that a
resilient dividend intended to remain fixed at 5.25 cents per ordinary
share per quarter (subject to the board’s decision each quarter), with
a commitment to return at least 60% of surplus cash« to shareholders
through share buybacks (having reached $35 billion net debt« and
subject to maintaining a strong investment grade credit rating), was in
the best interest of the company, its shareholders as a whole and other
stakeholder groups, as it enabled bp to offer sustainable value with
increased investment in low carbon and non-oil and gas ventures.
bp Annual Report and Form 20-F 2020
83
Corporate governance continued
Independence
Non-executive directors (NEDs) are expected to
exercise independent judgement and to be free
from any business or other relationship that could
materially interfere with it. This independence is
crucial in bringing constructive challenge to the
CEO and the leadership team at board meetings,
while providing support and guidance to promote
meaningful discussion and, ultimately, informed
and effective decision making.
The board regularly reviews the independence of
its NEDs, as advised by the company secretary,
and takes action to identify and manage conflicts
of interests, including those that may arise from
significant shareholdings. This process helps to
ensure that the influence of third parties does not
compromise or override independent judgement.
Directors are required to provide sufficient
information to allow the board to evaluate their
independence prior to and following their
appointment. As a consequence of regular
reviews throughout the year, the board has
satisfied itself that there were no matters
giving rise to any conflict of interests or which
compromised the independence of the NEDs.
It has therefore concluded that all bp NEDs
are independent.
Professor Dame Ann Dowling continues to serve
on the board notwithstanding that she has served
beyond nine years as a NED. Following careful
consideration, the board believes that Ann
continues to provide constructive challenge and
robust scrutiny of matters that come before the
board and the committee on which she serves.
She has only served with the current executive
directors for a year and the overall average tenure
of the board is below the FTSE 100 average. In
addition, in 2018 the board undertook significant
refreshment of its composition. Accordingly,
the board is satisfied that Ann continues to
demonstrate the qualities of independence
in carrying out her duties.
Appointment and time
commitment
The chairman, senior independent director
and other NEDs each have letters of appointment
and do not serve, nor are they employed, in any
executive capacity. There is no fixed term limit
on a director’s service; however, in line with good
governance practice, bp proposes all directors
for annual re-election by shareholders.
Unlike the chairman’s letter of appointment, the
NEDs’ letters of appointment do not set a fixed
time commitment. NEDs are expected to allocate
appropriate time to effectively discharge their
duties. The time required of NEDs fluctuates
depending on the demands of bp business and
other events. The COVID-19 pandemic, as well
as the oversight by the board of the energy
transition and associated workload, required
the NEDs to spend considerably more time
fulfilling their responsibilities towards bp during
2020, than in previous years. This included
NEDs dedicating additional time through regular
calls with the leadership team to remain informed
and help guide the executive through
unprecedented times.
The NEDs’ external time commitments are
regularly reviewed, ensuring that, even in the
exceptional circumstances of a global pandemic,
the NEDs are able to allocate appropriate time
to bp. The review process is managed by the
company secretary, considering NEDs’ outside
appointments and commitments, including
relevant factors such as complexity of company
and industry, in particular highly regulated
sectors, and issues impacting these other
companies. The board has concluded that,
notwithstanding the NEDs’ other appointments,
they are each able to dedicate sufficient time
to fulfil their bp duties.
Executive directors are normally permitted to
take up one board appointment at an external
company, subject to the agreement of the
chairman and after consultation with the
company secretary. Bernard Looney and Murray
Auchincloss each hold one non-executive
directorship, shown on page 74. Prior to retiring
from the board in June 2020, Brian Gilvary
undertook a role as NED of Barclays PLC, in
addition to his NED role with L’Air Liquide S.A..
Following consideration, it was concluded that
Brian’s two external appointments were unlikely
to be detrimental to his ability to perform his
duties as outgoing CFO.
Diversity
At a time of significant change across the sector,
and with bp transitioning to become an Integrated
Energy Company, diversity of thought is as
important as ever.
Our purpose, to reimagine energy for people
and our planet, can only be achieved through
collaboration, innovation and constructive
challenge that derives from having a diverse
and inclusive workplace. The board understands
and advocates that better decisions and
outcomes are achieved when different people,
with differences of opinions, from different
backgrounds, come together with a
common ambition.
We recognize that diversity can take many
forms, whether it be gender, social or ethnic
backgrounds, personal identities, age, religion,
physical abilities and more. All of which promote
diversity of thought and reduce the risk of group
think. The board has, and continues to have,
regard to all these forms of diversity in respect
of its processes including both its appointments
and succession plans.
The board and leadership team believe in leading
by example and are pleased to have met the
Hampton-Alexander and Parker review targets
for 2021.
At the end of 2020 the board comprised five
female directors, representing 45% of the
board (2019 42%, 2018 35%).
Karen Richardson and Johannes Teyssen
joined the board on 1 January 2021.
Dame Alison Carnwath stepped down
from the board on 14 January 2021.
As previously announced, Brendan Nelson
will be stepping down from the board at the
conclusion of the 2021 AGM.
The board is pleased that Tushar Morzaria,
a Ugandan-born British national, joined in
September 2020. He will succeed Brendan
Nelson as audit committee chair following
the 2021 AGM.
Our senior management, as defined by the
Corporate Governance Code 2018, and their
direct reports comprise 43% women (2019 38%)
and 25% Black, Asian and minority ethnic
(BAME) individuals (2019 18%).
While bp continues to benefit from the wide
array of perspective and vision in decision-making
processes and the company culture continues to
strengthen through mitigation of group think, bp
will continue to strive for increased diversity
across its workforce, leadership team and board.
For more information on our workforce diversity
and inclusion see page 57.
84
bp Annual Report and Form 20-F 2020
Corporate governance
Remuneration
committee
Geopolitical
committee
People and
Governance
committee
A
1
3
3
B
1
2
3
A
4
9
9
5
B
4
7
7
5
9
9•
8
9•
A
7•
3
7
7
7
7
B
7•
3
7
6
7
7
6
6
3•
3•
Safety and
sustainability
committee
A
2
B
2
6
6•
6
6•
Attendance
Non-executive directors
Helge Lund
Nils Andersen
Dame Alison Carnwath
Pamela Daley
Sir Ian Davis
Professor Dame Ann Dowling
Melody Meyer
Tushar Morzaria
Brendan Nelson
Paula Reynolds
Sir John Sawers
Executive directors
Murray Auchincloss
Bob Dudley
Brian Gilvary
Bernard Looney
Board
Audit committee
A
B
A
B
10
10
10
9
3
10•
10
3
10•
10
10•
3
10
10
10
10
10
3
10
10
10
5
2
5
8
10•
2
10
9
9
9
10
3
10
10
10
5
2
5
8
A Possible meetings B Attended meetings • Chair of board/committee
bp Annual Report and Form 20-F 2020
85
Corporate governance continued
How the board has engaged with shareholders,
the workforce and other stakeholders
Institutional investors
We regularly engage with our institutional
shareholders through an active investor
relations programme. COVID-19 has meant that
this engagement had to move online for the
majority of 2020. The pinnacle of this virtual
engagement was bp week in September 2020,
led by Bernard Looney and members of his
leadership team. The team innovatively engaged
with shareholders giving detailed insights into
bp’s new strategy and the 2025 and 2030 targets
and aims. This engagement was also deliberately
structured to allow for the increasingly important
ESG constituency to be consulted in determining
the targets and aims, including the overlay of
the new sustainability frame in support of the
new strategy.
The board receives feedback from shareholders
in many ways, particularly through the chairman
and leadership team who meet with investors
throughout the year. Numerous one-to-one
meetings with major institutional investors
and proxy advisory groups were hosted by
the chairman in 2020. These engagements
generated much insightful feedback which
was shared with other board members and
committees with due regard being given
to these views. A similar programme of
engagement on matters relating to the
2020 directors’ remuneration policy that
was approved by shareholders at the AGM
was undertaken during the year, led by the chair
of the remuneration committee and senior
independent director, Paula Reynolds. More
details about this engagement are set out in the
2020 directors’ remuneration report on page 103.
Retail investors
In May we held our annual event for
retail investors in conjunction with the UK
Shareholders’ Association (UKSA) and the
UK Individual Shareholders Society. For the
first time this event was held virtually. The
chairman, company secretary and head of
investor relations gave presentations on bp’s
annual results, strategy and the work of the
board. Shareholders’ questions were primarily
focused on bp’s response to the COVID-19
pandemic, bp’s sustainability strategy and
financial performance.
AGM
In common with the practice adopted by many
UK quoted companies, the 2020 AGM was held
as a ‘closed’ meeting, with a minimum quorum
present, in line with government rules at the time.
Shareholders were invited to submit questions to
the board before the meeting, all of which were
addressed, and the event was broadcast live via
webcast on bp.com.
As expected, voting levels saw a slight decrease
with the pandemic and stay-at-home orders
disrupting shareholder voting. The overall turnout
was 62.1% of the total voting rights, including
votes cast as withheld, compared to 67.1% in
2019 and 67.3% in 2018. All resolutions passed
at the meeting in line with the board’s
recommendations.
At the date of this report, measures put in
place by the UK government in response to
the COVID-19 pandemic preclude bp from
holding an AGM in person. In these exceptional
circumstances, bp’s 2021 AGM is planned to
be a hybrid meeting. Shareholders will not be
permitted to attend the meeting in person, but
will be able to participate via bp’s electronic
meeting platform.
The board will continue to monitor developments
in UK government guidance relating to the
COVID-19 situation. If circumstances change
materially before the date of the AGM, the board
may decide to adapt proposed arrangements.
Shareholder engagement cycle 2020
Q1
Q2
Q3
Fourth quarter and full-year 2019
results and strategy update
Ambition launch
Investor roadshows with the leadership
team post the ambition launch
bp Annual Report and Form 20-F 2019
bp Sustainability Report 2019
First quarter 2020 results presentation
Investor roadshows with executive
management following first quarter
2020 results
UKSA (retail shareholders’) meeting
with the chairman
Other institutional shareholder
engagement with the chairman
2020 AGM
bp Statistical Review of World Energy
Second quarter 2020 results and
strategy presentation
Investor roadshows with executive
management follow second quarter
2020 results and strategy
Capital markets event – ‘bp week’
bp Energy Outlook presentation
Investor roadshows with the
bp leadership team – capital
markets event
Q4
Third quarter 2020 results presentation
Investor roadshows with the bp
leadership team following third quarter
2020 results
86
bp Annual Report and Form 20-F 2020
Corporate governance
A regular programme of engagement has been
developed. Some sessions have a specific
engagement purpose while others will simply
be an open opportunity to hear views, interests,
ideas and concerns. It is intended that a number
of these sessions will have no line managers to
allow for an unconstrained exchange of views.
Engagement locations will be varied across our
global operations. Alongside this programme,
the ‘Pulse’ surveys, bp ‘Keeping Connected’
sessions, site visits (even if virtual) and the
chairman’s programme of attendance at selected
small team sessions will continue.
The board believes the existing approaches
and mechanisms described above enable
comprehensive two-way engagement
opportunities with bp’s workforce, and as such,
is satisfied that these are effective alternatives
to the proposed workforce engagement methods
set out in Provision 5 of the Code.
Looking beyond 2021 the board will continue to
assess the effectiveness of its engagement with
the workforce and how ultimately this informs
the decisions that it takes, including the options
provided for in the Code, for example appointing
a director from the workforce.
Workforce
2020 engagement
We believe an engaged workforce is critical
to us successfully delivering our strategy.
When we talk about bp’s workforce, we
include a wide range of employees, contractors,
agency and remote workers across all of our
geographical locations.
The board is responsible for overseeing and
monitoring bp’s culture and its values. This
extends to putting in place mechanisms allowing
for workforce views to be reflected in board
discussion and decision making, complementing
existing mechanisms that are established by the
leadership team.
Such measures include employees being
informed on matters of concern to them
through bp’s intranet and local sites, social
media channels, town halls, site visits and
webinars including topics such as quarterly
results, strategy, the low carbon transition
and diversity.
We also have a number of employee-led forums
and business resource groups (BRGs) and aim to
build constructive relationships with labour unions
formally representing some employees.
Employees are consulted on a regular basis
through regular team and one-to-one meetings
and through our annual ‘Pulse’ survey.
The board believes that the approaches and
mechanisms described under Site visits, below,
enabled effective engagement opportunities
with the bp workforce.
The board is satisfied that during 2020, these
were effective alternatives to the proposed
workforce engagement methods set out in
Provision 5 of the UK Corporate Governance
Code (the Code).
Future of workforce engagement
As part of its broader review of bp’s corporate
governance framework, the board discussed
whether its current approach to workforce
engagement continues to be the most effective
mechanism to inform its discussions and the
decisions that it takes.
Building on the experience that we have had,
and the innovative approaches that were taken to
workforce engagement through 2020, the board
has sought to create a more rigorous framework
so that there is clear channel through which the
insights emerging from this engagement process
will be consolidated and considered in board
discussions and decision making. The board
also considered the significant changes to the
workforce following reinvent bp and bp’s wide
geographic spread and size. Taking all these
factors into account, the board concluded
that for 2021 workforce engagement is best
overseen by the newly constituted people
and governance committee.
Virtual engagements
Virtual site visits
During 2020 restrictions
associated with COVID-19
disrupted planned
opportunities for the board
to engage with the bp
workforce in person. As a
result, most engagements
were conducted virtually.
The audit committee conducted a
virtual visit and tour of bp’s trading
floors in London and Houston and
a majority of our non-executive
directors attended a virtual visit of
bpx energy’s Permian assets, led
by the safety, environment and
security assurance committee.
During these visits, directors
heard directly from the workforce
regarding their perceptions of bp’s
new strategy and how these
businesses planned to implement
it, as well as deepening their
understanding of businesses
and functions within bp.
Business resource groups
and focus groups
Non-executive directors engaged
virtually with employees in BRGs
and focus groups throughout the
year, including virtual events
organized by the Women in Wells,
Future Talent and One Young World
alumni forums. Through these
engagements the directors heard
directly from employees on a range
of topics, including bp’s new
purpose and strategy, employee
sentiment – particularly during
the reorganization of bp – the
impact of COVID-19 on operations
and wellbeing, diversity and
career progression.
CEO ‘Keeping
Connected’ webcasts
Our CEO Bernard Looney hosted
a series of webcasts featuring
guests from across the
organization to discuss a range
of topics throughout the year,
including bp’s new purpose,
safety, mental health, and
reinventing bp. Helge Lund,
chairman of the board, joined the
CEO as a speaker on two of these
webcasts and non-executive
directors were also invited to
listen in.
>12,500
average viewers
per webcast
bp Annual Report and Form 20-F 2020
87
Corporate governance continued
Governance framework
We completely redesigned the bp corporate
governance framework in 2020, to more closely
align with bp’s new purpose – reimagining energy
for people and our planet – as well as our new
strategy. The framework defines the board’s role,
to promote the long-term sustainable success
of the company, generating value for its
shareholders while having regard to its other
stakeholders, the impact of its operations on
the communities within which it operates and
the environment.
The review had three main strands:
1. The role and purpose of the board
The bp board believes that in order for
governance to be effective it needs to have a
regular review process across purpose, strategy,
culture and values, while maintaining oversight
of performance. Clearly defined terms of
reference for the board were established together
with a roadmap of activity that reflects those
issues the board consider most important.
The board terms of reference identify certain
matters that are considered to be of such
materiality at a group level that they are reserved
for approval by the whole board and cannot be
delegated. The matters reserved include, among
others, certain investments, entry into new
countries, changes to the company’s capital
structure, distributions and bp’s code of conduct.
The full list is available on bp.com/governance.
88
bp Annual Report and Form 20-F 2020
Purpose
Considers bp’s purpose, which
underpins its decision making.
Monitors whether bp’s strategy,
values and culture remain in line
with that purpose.
Values
The board monitors bp’s values,
ensuring that they are appropriate as
the leadership team focuses on the
execution of the new strategy.
Board
governance and
performance
oversight
Culture
Reviews the ambition and aims of
the people plan and in so doing
assesses and monitors any impact
on culture so as to satisfy itself that
bp’s purpose, strategy and values
continue to be aligned with
its culture.
Strategy
Receives regular updates to test
that the strategy and strategic
direction established by the board
continue to be the right approach
for the long-term sustainable
success of bp in line with
its purpose.
Through the people and governance
committee, reviews work on bp’s
ways of working (including
integration, agility, wellbeing,
workplace, inclusion and digital).
Approves the annual plan and
regularly monitors that it is aligned
with the approved strategy, including
reviewing business development,
investment effectiveness and
capita allocation.
Conducts deep dives across each
of the business groups and key
strategic areas.
Receives regular updates on
progress towards the aims and
objectives in the sustainability frame.
Corporate governance
2. Committees
A review of the board committees looking at their
purpose, scope and authority with a focus on:
Fit with the strategic direction of the bp board.
Risk and allocation of the review of risk.
Alignment with the new leadership structure
to give clear oversight.
The new committee structure under the
board is depicted in the diagram (right) and
described below.
The nomination and governance committee
was renamed the people and governance
committee to reflect its wider remit in covering
workforce engagement, wellbeing and talent
management.
The safety, environment and security
assurance committee was renamed the
safety and sustainability committee. Its remit
has been widened to include monitoring the
effectiveness of implementation of bp’s
sustainability frame, see page 48. This is an
important step in light of bp’s new purpose
and ambition.
The other permanent committees –
remuneration and audit – will remain. The
results committee (comprising the chairman,
CEO and chief financial officer (CFO)) also
remains with delegated authority from the
board to approve and authorize the release of
the periodic financial statements and dividend
announcements.
The geopolitical committee has been replaced
by a geopolitical advisory council rather than a
board committee. It is attended by members
of the board and the executive together with
advisors who give a wider external view. The
geopolitical highest priority risk is overseen at
the board.
Each of the four permanent committees has
new terms of reference, adopted from 1 January
2021, to set out their role and responsibilities in
a clear mandate, which can be found on
bp.com/governance.
The board will continue to review its framework
annually to satisfy itself that it continues to be
best aligned to bp’s purpose and strategy.
Board and board committee structure
Board
People and
governance
committee
Remuneration
committee
Audit
committee
Safety and
sustainability
committee
The changes to bp’s purpose and strategy
this year and bp’s journey towards becoming
an Integrated Energy Company have given rise
to the need for greater visibility on the decision-
making criteria for capital expenditure and new
business transactions. Accordingly, the board
spends time examining and discussing the
impact of portfolio changes such as strategic
acquisitions and the allocation of capital,
along with the annual plan, in order to gain
a clear understanding of the methodology
of capital allocation.
The board reviews capital investments that are
more than $3 billion for resilient hydrocarbons,
more than $1 billion for all transition or low carbon
investments and, in addition, any significant
inorganic acquisition that is exceptional or
unique in nature.
Clear information flows have been established
between the board and the leadership team.
This allows greater time at board meetings to
focus on strategic and people topics, enabling
a fuller understanding and quality discussion
of the challenges to deliver our new strategy.
3. New ways of working
The board’s corporate governance review
extended to documenting the responsibilities
of the chairman, the CEO and the senior
independent director so that their respective
roles are clear both internally and to our
external stakeholders. These are available
on bp.com/governance.
The board delegates day-to-day management
of the business of the company to the CEO.
This includes accountability to oversee the
implementation of a comprehensive system
of internal controls that are designed to, among
other things, identify and manage the risks
that are material to bp.
The board continues to perform its oversight
role and monitor bp’s performance. This
responsibility extends to monitoring bp’s
management and operations and obtaining
assurance about the delivery of its strategy,
and to oversee bp’s internal control and risk
management frameworks. The chairman holds
meetings without executive directors present
at the start or end of board meetings.
The CEO is responsible for maintaining a dialogue
with the chairman and the board on important
and strategic issues facing bp. Strategic
opportunities or issues which may arise, or which
are on the CEO’s mind, are discussed at board
meetings and the CEO welcomes constructive
challenge from non-executive directors in light
of their wider experience outside bp.
bp Annual Report and Form 20-F 2020
89
Corporate governance continued
Learning, development and induction
The developmental needs of the board as a whole and for individual directors are regularly reviewed,
so as to ensure that the board and individual effectiveness to board discussion and decision making
are maximized. A formal and comprehensive induction is provided to all directors following their
appointment. This includes meetings with management, technical briefings and site visits.
Board induction programme
Tushar Morzaria, appointed on 1 September
2020, undertook a tailored and robust induction
against the challenging backdrop of COVID-19.
Tushar looks forward to continuing his
introduction to bp’s operations and learning
more about the business and its people.
The programme was adapted to accommodate
the inability to participate in physical meetings
and site visits. Digital solutions were therefore
deployed to facilitate Tushar’s induction.
The programme included meetings with a wide
range of senior management within bp, the
external auditor and other key advisors. A
selection of these and the areas of focus are
outlined below.
I am delighted to join the
bp board and to contribute
my expertise in support of
bp’s new strategy.
Tushar Morzaria
Independent
non-executive
director
Area
Board and governance
Audit committee
Provided by
Key topics covered
Helge Lund, chairman
Ben Mathews, group company secretary
Brendan Nelson, chair of the audit
committee
Jayne Hodgson, SVP, accounting,
reporting, control
David Jardine, SVP internal audit
Doug King, Deloitte (external audit partner)
Overview of board and committee matters.
Priority areas for the board.
Governance framework.
Corporate structure.
Priority areas for the committee, including
committee chair succession.
bp’s financial position.
Financial reporting framework and
quarterly results close cycle.
Internal audit reports.
External audit and quarterly review reports.
bp’s new strategy and sustainability focus.
Overview of legal matters, including
material litigation.
Overview of treasury matters and liquidity
risk management.
Strategy and sustainability
Legal
Treasury
Giulia Chierchia, EVP
strategy & sustainability
Eric Nitcher, EVP legal
Kate Thomson, SVP treasury
90
bp Annual Report and Form 20-F 2020
Corporate governance
Board evaluation
Each year bp completes a formal and rigorous annual evaluation
of the performance of the board, its committees, the chairman
and individual directors.
There is also a triennial requirement for this evaluation to be externally facilitated
which will next fall due in 2021.
The 2019 board evaluation highlighted three specific areas for action in 2020:
Focus area
Action taken
Review the skills, experience and diversity
of the board, and the process for executive
succession planning and talent management
and development.
Satisfy itself that every member of the board has
a deeper understanding of the board’s role in
determining bp’s capital allocation process and in
enabling more effective decision making.
Redesign bp’s corporate governance framework,
reinforcing the effectiveness of this control
framework so that it is more closely aligned with
bp’s new purpose and strategy.
The board skills matrix was used to focus NED
recruitment and we have successfully recruited
three NEDs with strong experience in areas
which will complement and support bp’s new
strategy and provide diversity of thought.
The board, through the former nomination and
governance committee, heard regular updates
on the selection process and criteria for the bp
leadership team and the next layer of leadership
with a focus on building a future succession
pipeline and the skills needed to drive the
execution of bp’s new strategy.
The board and leadership team have developed
a process for greater visibility of capital allocation
at the board and evaluated the methodology
of capital allocation. Capital allocation above
agreed thresholds is now a matter reserved
for the board.
The board governance framework and ways
of working were redesigned, details of which
can be found on page 88.
The 2020 board evaluation was an internal
review. The chairman spoke with each director
individually. The company secretary facilitated
a theme-based review including, among other
matters, portfolio management, the impact of the
new board agenda, the evolution of bp’s purpose,
strategy and values, stakeholder engagement and
people matters. The review also looked at the
composition and diversity of the board and how
effectively the directors work together.
In early 2021, the board held a special meeting to
discuss the feedback, focusing on strategic and
operational oversight, board development and
maintaining a dynamic and flexible approach to
board and committee agendas. An action plan
for areas of focus was agreed.
Following this meeting, the senior independent
director led a meeting with the non-executive
directors without the chairman present to
appraise his performance. The directors
expressed their strong support for the
continued leadership shown by the chairman.
bp Annual Report and Form 20-F 2020
91
Corporate governance continued
People and governance committee
Chair’s introduction
I am pleased to present my report as chair
of the people and governance committee.
During 2020, the committee reviewed the
composition of the board and, with the new
purpose and strategy in mind, focused on
identifying candidates who would enhance the
strategic discussion in the boardroom and add to
the diversity, skills and experience required as bp
transitions to an Integrated Energy Company.
We discussed and guided the development of
the new board governance framework to satisfy
ourselves that bp continues to maintain the
highest standards of governance and we
reviewed bp’s workforce engagement
mechanism options in order to make a clear
recommendation to the board. As part of the
governance review, the committee was renamed
as the people and governance committee with
effect from 1 January 2021 to reflect its wider
remit in covering workforce engagement,
wellbeing and talent management.
Looking to 2021, the committee agenda has been
restructured to cover four matters: talent and
capability, diversity and inclusion, engagement
and culture and governance. Under that umbrella,
we will oversee workforce engagement, engage
an external provider for board effectiveness and
continue to look at succession, leadership, talent,
diversity and culture matters.
Helge Lund
Committee chair
Committee overview
Role of the committee
The people and governance committee (previously
called the nomination and governance committee,
until 31 December 2020) seeks to ensure an orderly
succession of candidates for directors, the company
secretary and senior executives and oversees
corporate governance matters for the group.
Key responsibilities
Identify, evaluate and recommend candidates for
appointment or reappointment as directors.
Identify, evaluate and recommend candidates for
appointment as company secretary.
Review the mix of knowledge, skills, experience
and diversity of the board for the orderly
succession of directors.
Review the outside directorships/commitments of
the non-executive directors (NEDs).
Review developments in law, regulation and best
practice relating to corporate governance and make
recommendations to the board on appropriate
action, including on environmental, social and
governance matters.
Meetings and attendance
The committee met seven times in 2020. All
members attended each meeting with the exception
of Brendan Nelson who missed one meeting owing to
a prior commitment.
Membership
Helge Lund
Sir Ian Davis
Nils Andersen
Member since July 2018
and chair since September
2018
Member (resigned
December 2020)
Member (resigned
March 2020)
Brendan Nelson
Paula Reynolds
Sir John Sawers
Member
Member
Member
The committee focused on
identifying candidates who would
enhance the strategic discussion
in the boardroom and add to the
diversity, skills and experience
required as bp transitions to
an IEC.
Helge Lund
Committee chair
92
bp Annual Report and Form 20-F 2020
Corporate governance
The committee received regular updates and
challenged management on the reinvent bp
proposals including the scale of the redundancies,
the methodology associated with the selection
process and details of the process controls and
management of change to satisfy itself that
safety would be maintained and a respectful
process completed.
The committee heard detailed considerations
on the workforce engagement mechanism
options and discussed the benefits and issues
of each option presented in order to make a
recommendation to the board for 2021.
Activities during the year
Reflecting its role in respect of board succession
planning, early in 2020, the committee’s priority
was to identify new non-executive directors to
succeed two of the longer-serving members of
the board – Sir Ian Davis and Brendan Nelson.
Candidates were sought with the technical
and professional skills to take on certain
committee responsibilities, including in particular
the chairmanship of the audit committee,
plus also candidates who would be able to
support the chair of the board as the senior
independent director.
These characteristics were broadened so as to
identify candidates who would also enhance the
strategic discussion in the boardroom. External
headhunters were engaged to support the
process and identify candidates. These
headhunters had no other connection to the
company or its directors during the year.
The search process led to the appointment of
Tushar Morzaria in September 2020 and, from
among the existing board members, Paula
Reynolds as the senior independent director.
Each of these appointments was considered to
fulfil the search criteria, including the succession
of the audit committee chairmanship.
The committee also agreed new search
categories for other NED candidates, broadly
covering the areas of digital/technology and
energy, reflecting the strategic shift of bp to
become an Integrated Energy Company and the
dependency on digital as an enabler to transform
companies. Karen Richardson and Johannes
Teyssen together bring extensive financial,
technological, transformation and energy industry
experience to the board.
Planning for new board members to help ensure
a strong focus on strategic execution, safety and
sustainability and connectivity to bp’s core
businesses and markets continues.
Committee meetings in 2020 included updates
and discussions on the redesign of bp’s corporate
governance framework, more details of which are
set out on page 88.
Operational
excellence
and risk
management
Global business
leadership and
governance
People
leadership and
organizational
transformation
Technology,
digital and
innovation
Energy markets
Society, politics
and geopolitcs
Finance, risk,
trading
Background and experience
Skills matrix
Non-executive directors
Pamela Daley
Ann Dowling
Helge Lund
Melody Meyer
Tushar Morzaria
Brendan Nelson
Paula Reynolds
Karen Richardson
Sir John Sawers
Johannes Teyssen
bp Annual Report and Form 20-F 2020
93
Corporate governance continued
Audit committee
Membership
Brendan Nelson
Member since November
2010 and chair since
April 2011
Dame Alison Carnwath Member (resigned from the
board in January 2021)
Pamela Daley
Paula Reynolds
Tushar Morzaria
Member
Member
Member since
September 2020
(chair-designate)
Brendan Nelson is chair of the audit committee. See
page 76 for his biography. The board is satisfied that
he is the audit committee member with recent and
relevant financial experience as outlined in the UK
Corporate Governance Code and competence in
accounting and auditing as required by the FCA’s
Corporate Governance Rules in DTR7. It considers
that the committee as a whole has an appropriate and
experienced blend of commercial, financial and audit
expertise to assess the issues it is required to
address, as well as competence in the oil and gas
sector. The board also determined that the audit
committee meets the independence criteria
provisions of Rule 10A-3 of the US Securities
Exchange Act of 1934 and that Brendan may be
regarded as an audit committee financial expert as
defined in Item 16A of Form 20-F.
Committee overview
Role of the committee
The committee monitors the effectiveness of the
group’s financial reporting (including reporting on the
financial aspects of climate matters), systems of
internal control and risk management and the integrity
of the group’s external and internal audit processes.
Key responsibilities during 2020
Monitoring and obtaining assurance that the
process to identify, manage and mitigate principal
and emerging financial risks are appropriately
addressed by the CEO and that the system of
internal control is designed and implemented
effectively in support of the limits imposed by the
board (‘executive limitations’).
Overseeing the appointment, remuneration,
independence and performance of the external
auditor and the integrity of the audit process as a
whole, including the engagement of the external
auditor to supply non-audit services to bp.
Reviewing the effectiveness of the internal audit
function, bp’s internal financial controls and
systems of internal control and risk management.
Reviewing financial statements and other financial
disclosures and monitoring compliance with
relevant legal and listing requirements.
Reviewing the systems in place to enable those
who work for bp to raise concerns about possible
improprieties in financial reporting or other issues
and for those matters to be investigated.
Meetings and attendance
There were 10 committee meetings in 2020. All
members attended each meeting with the exception
of Pamela Daley who was absent from the March
meeting owing to prior commitments. Regular
attendees at the meetings include the chief financial
officer, SVP accounting reporting control, SVP internal
audit, EVP legal and external auditor.
The committee was
particularly focused on the
impacts of bp’s reorganization
and the COVID-19 pandemic
on financial performance, the
financial control environment
and resilience.
Brendan Nelson
Committee chair
94
bp Annual Report and Form 20-F 2020
Corporate governance
Chair’s introduction
I am pleased to introduce the report on the audit
committee’s activities during the year. During the
year, the committee has continued to assist the
board in fulfilling its oversight responsibilities, by
monitoring the integrity of the group’s financial
reporting and risk management systems, and
also by challenging management and external
auditors across a number of key areas of focus,
including key accounting judgements and
control issues.
In addition to the routine committee agenda for
the year, the committee was particularly focused
on the impacts of bp’s reorganization and the
COVID-19 pandemic on financial performance,
the financial control environment and resilience.
I welcome the addition of Tushar Morzaria to the
committee from September 2020. His broad
financial experience is immensely beneficial to
the committee and bp. Following year end, Dame
Alison Carnwath stepped down from the
committee and the board. I would like to thank
her for her diligent contribution to the committee
over the years.
This is my last report as chair of the audit
committee. I would like to thank my board and
committee colleagues, as well as management,
for the open, challenging and constructive nature
of discussions we have conducted during my
tenure. As I hand over the committee chair
to Tushar in May 2021, I remain confident that
bp is well-positioned for continued resilience
and success.
Brendan Nelson
Committee chair
Activities during the year
How the committee reviewed
financial disclosure
The committee reviewed the quarterly,
half-year and annual financial statements
with management, focusing on the:
Integrity of the group’s financial
reporting process.
Clarity of disclosure.
Compliance with relevant legal and
financial reporting standards.
Application of accounting policies
and judgements.
As part of its review, the committee received
regular updates from management and the
external auditor in relation to accounting
judgements and estimates, including those
relating to recoverability of asset carrying values.
The committee keeps under review the
frequency of results reporting during the year.
In considering the bp Annual Report and Form
20-F, the committee assessed whether the
report was fair, balanced and understandable
and also whether it provided the information
necessary for shareholders to assess the
group’s position and performance, business
model and strategy. In making this assessment,
the committee examined disclosures during
the year, discussed the requirement with senior
management, confirmed that representations
to the external auditors had been evidenced
and reviewed reports relating to internal
control over financial reporting. The committee
made a recommendation to the board, who
in turn reviewed the report as a whole,
confirmed the assessment and approved
the report’s publication.
How accounting judgements
and estimates were considered
and addressed
The committee was briefed on a quarterly
basis in 2020 on the group’s key accounting
judgements and estimates. The primary areas
of judgement and estimation which were
considered by the committee are set out below.
These areas were discussed with management
and the external auditor throughout the year
and during the preparation of these financial
statements. The committee is satisfied that
the financial statements appropriately address
the key accounting judgements and estimates
both in respect of the amounts reported and
disclosures made.
During the year, the committee also considered
and approved a change to bp’s accounting policy
relating to physically settled commodity
contracts, with effect from 1 January 2021.
The committee’s process for considering key
accounting judgements and estimates included
an assessment of matters at various stages
during the year. This primarily included the key
accounting judgements and estimates set out on
pages 98 and 99. The committee also considered
and addressed key accounting estimates and
judgements relating to provisions, pensions and
other post-retirement benefits, and supplier
financing arrangements via briefings and review
of the group’s assumptions. See Notes 23, 24
and 29 respectively for further information.
bp Annual Report and Form 20-F 2020
95
Corporate governance continued
How risks were reviewed
The principal risks allocated to the audit
committee for monitoring in 2020 included
those associated with:
Trading activities: including risks arising
from shortcomings or failures in systems, risk
management methodology, internal control
processes or employees.
In reviewing this risk, the committee focused
on external market developments and how
bp’s trading function had responded to a rapidly
changing environment, including enhancing
its control environment policies to strengthen
its compliance and control culture. The
committee further considered updates in the
trading and shipping function’s risk management
programme, including compliance with regulatory
developments, activities in response to cyber
threats, and efficiencies derived from more
collaborative ways of working across group
functions and businesses and the use of digital
technologies. The committee also considered
the impact of COVID-19 on operations and the
control environment associated with trading
activities, with particular reference to operational
considerations associated with increased
remote working.
Compliance with business and regulations:
including ethical misconduct or breaches of
applicable laws or regulations that could damage
bp’s reputation, adversely affect operational
results and/or shareholder value and potentially
affect bp’s licence to operate.
The committee reviewed the group’s programme
on controls and contingencies for managing this
risk, including enhanced approaches to monitor
the risk in light of business evolution (such as an
increase in venturing), as well as other internal
and external trends.
Cyber security risk: including inappropriate
access to or misuse of information and systems
and disruption of business activity.
The committee reviewed ongoing developments
in the cyber security landscape, including events
in the oil and gas industry and within bp itself.
The review focused on a strengthened approach
in order to manage the ever-increasing threat
of cyber risk and maintain cyber security, as
the focus on a digital transformation across
bp continues.
Financial liquidity: including the risk associated
with external market conditions, supply and
demand and prices achieved for bp’s products
which could impact financial performance.
The committee reviewed the key assumptions
and underlying judgements used to manage
the group’s liquidity and capital investments
(including appraisal, effectiveness and efficiency).
How other reviews were undertaken
Other reviews undertaken in 2020 by the
committee included the following, and in each
case where the committee received segment
and function reviews, each reported on strategy,
performance, capability and risk management as
well as on their first, second and third lines of
defence policies as appropriate:
Information technology and services: including
the functions performance, strategy and
optimization of core services to enable the
digitization and modernization of bp at pace.
bp ventures and Launchpad: including the
purpose, capabilities, operating model,
governance and performance of these entities.
Reinvent bp programme: including a review
of programme milestones and risks, as well
as business continuity and management
of change.
Tax: including strategy, performance, key
drivers of the group’s effective tax rate, the
global indirect tax environment, the tax
modernization programme and the evolving
approach to management of key risks.
The committee also reviewed bp’s tax
transparency report.
Internal audit functional review: including
a five-year plan for the function in a
reinvented bp.
Trading and shipping: including strategy,
performance, capability and risk management.
Effectiveness of investment: annual review
of performance of projects with sanctioned
capital over a certain threshold.
Internal controls: assessments of
management’s plans to remediate the external
auditor’s control findings.
How internal control and risk
management was assessed
Internal audit
The committee received quarterly reports on
the findings of internal audit in 2020, including
their assessment of issues raised in previous
years, especially those relating to IT access
controls. The committee also received a report
from internal audit on their annual review of the
system of internal control and risk management.
The committee met privately with the SVP,
internal audit and key members of his leadership
team. The committee continued to monitor and
review the effectiveness and capabilities of
internal audit during the year. During the year, the
committee received a report on the findings of
an assessment conducted by internal audit of
its conformance with the Internal Audit Code of
Practice which was published in January 2020.
The committee noted that internal audit conforms
with the vast majority of recommendations set
out in the code. Actions to achieve full
conformance with the code were also noted.
Training and briefings
The committee considered market updates and
developments throughout the year. This included
technical accounting updates from the SVP
accounting reporting control on developments
in financial reporting and accounting policy, as
well as on accounting and disclosure changes
that would be introduced as a result of the
reorganization of the group. The committee also
received briefings on specific topics, including
non-operated joint ventures, and data analytics
used by the external auditor.
Site visit during the year
In October 2020, the committee conducted a
virtual visit of the trading & shipping function,
including virtual presentations from the trading
floor, covering low carbon trading, global power
and global crude. Key areas of discussion during
this site visit included the impacts of oil price
volatility, COVID-19 and the reinvent bp
programme on the business and its operations
during 2020.
96
bp Annual Report and Form 20-F 2020
FRC thematic review
The bp Annual Report and Form 20-F 2019 was
included in the FRC’s sample for its limited scope
thematic review on reporting on the impact of
climate change. bp subsequently received a letter
request for information from the FRC’s Corporate
Reporting Review team. The audit committee
considered the letter and bp’s detailed response
thereto, which enabled the FRC to close its
enquiries. The committee notes the further
enhancements made to disclosures in relation
to climate change and the energy transition in
this annual report.
An FRC review provides no assurance that bp’s
Annual Report 2019 was correct in all material
respects. The FRC’s role was not to verify the
information provided but to consider compliance
with reporting requirements. Its letters are
written on the basis that the FRC (which includes
the FRC’s officers, employees and agents)
accepts no liability for reliance on them by bp
or any third party, including but not limited to
investors and shareholders.
External audit
How the committee assessed audit risk
The external auditor set out its audit plan for
2020, identifying significant audit risks to be
addressed during the course of the audit.
These included:
Impairment of upstream oil and gas property,
plant and equipment.
Impairment of exploration and appraisal assets.
Accounting for structured commodity
transactions.
Valuation of level 3 instruments in trading
and shipping revenue recognition.
Management override of controls.
The committee received updates during the
year on the audit process, including how the
auditor had challenged the group’s assumptions
on these issues.
How the committee assessed audit fees
The audit committee reviews the fee structure,
resourcing and terms of engagement for the
external auditor annually; in addition it reviews
the non-audit services that the auditor provides
to the group on a quarterly basis.
Fees paid to the external auditor for the year
were $54 million (2019 $49 million), of which
1.9% was for non-audit and other assurance
services (see Financial statements – Note 36).
The audit committee is satisfied that this level of
fee is appropriate in respect of the audit services
provided and that an effective audit can be
conducted for this fee. Non-audit or non-audit
related assurance fees were $1 million (2019 $1
million). Non-audit or non-audit related services
consisted of other assurance services.
How the committee assessed audit
effectiveness
Management undertook a survey which
comprised questions across the following:
(i) The main criteria to measure the auditor’s
performance were:
– Robustness of the audit process
– Independence and objectivity
– Quality of delivery
– Quality of people and service
(ii) bp’s commitment to the audit; and
(iii) Aligned audit approach – which sought to
measure progress against the commitments
from the audit tender.
Year on year, the overall score from the survey
increased by +3%. Improvements were seen
across audit effectiveness and service quality,
including a number areas of focus that had been
identified in the previous survey.
The committee also held private meetings with
the external auditor during the year and the
committee chair met separately with the external
auditor and group head of audit at least quarterly.
The effectiveness of the external auditor
is evaluated by the audit committee. The
committee assessed the auditor’s approach to
providing audit services. On the basis of such
assessment, the committee concluded that the
audit team was providing the required quality in
relation to the provision of the services. The audit
team had shown the necessary commitment and
ability to provide the services together with a
demonstrable depth of knowledge, robustness,
independence and objectivity as well as an
appreciation of complex issues. The team had
posed constructive challenge to management
where appropriate.
How the auditor reappointment and
independence was assessed
The committee considers the reappointment
of the external auditor each year before making
a recommendation to the board. The committee
assesses the independence of the external
auditor on an ongoing basis and the external
auditor is required to rotate the lead audit partner
every five years and other senior audit staff every
five to seven years. No partners or senior staff
associated with the bp audit may transfer to
the group.
Corporate governance
How the committee had oversight
of non-audit services
The audit committee is responsible for bp’s
policy on non-audit services and the approval
of non-audit services. Audit objectivity and
independence is safeguarded through the
prohibition of non-audit tax services and the
limitation of audit-related work which falls within
defined categories. bp’s policy on non-audit
services states that the auditor may not perform
non-audit services that are prohibited by the SEC,
Public Company Accounting Oversight Board
(PCAOB), International Auditing and Assurance
Standards Board (IAASB) and the UK Financial
Reporting Council (FRC).
The audit committee approves the terms of all
audit services as well as permitted audit-related
and non-audit services in advance. The external
auditor is considered for permitted non-audit
services only when its expertise and experience
of bp is important.
Approvals for individual engagements of
pre-approved permitted services below certain
thresholds are delegated to the SVP accounting
reporting control or the chief financial officer. Any
proposed service not included in the permitted
services categories must be approved in advance
either by the audit committee chair or the audit
committee before engagement commences.
The audit committee, chief financial officer and
SVP accounting reporting control monitor overall
compliance with bp’s policy on audit-related and
non-audit services, including whether the
necessary pre-approvals have been obtained.
The categories of permitted and pre-approved
services are outlined in principal accountant’s
fees and services on page 327.
bp Annual Report and Form 20-F 2020
97
Corporate governance continued
Examples of how accounting judgements and estimates were considered and addressed
Key judgements and estimates
in financial report
Exploration and appraisal intangible assets
Audit committee activity
Conclusions/outcomes
bp uses technical and commercial judgements
when accounting for oil and gas exploration,
appraisal and development expenditure.
Judgement is required to determine whether it
is appropriate to continue to carry intangible
assets related to exploration costs on the
balance sheet.
Judgemental aspects of oil and gas
accounting are reviewed routinely in bp’s
quarterly due diligence process.
Received the output of management’s
annual intangible asset certification process
used to verify that accounting criteria to
continue to carry the exploration intangible
balance are met.
Significant exploration write-offs were
recognized during the year (as disclosed
in Note 8).
Exploration intangibles totalled $4.1 billion
at 31 December 2020.
Recoverability of asset carrying values
Determination as to whether and how much an
asset, cash generating unit (CGU) or group of
CGUs containing goodwill is impaired involves
management judgement and estimates on
uncertain matters such as future commodity
prices, discount rates, production profiles,
reserves and the impact of inflation on
operating expenses.
Reserves estimates based on management’s
assumptions for future commodity prices have
a direct impact on the assessment of the
recoverability of asset carrying values reported
in the financial statements.
Impact of climate change and
the energy transition
Climate change and the transition to a lower
carbon economy may have significant impacts
on the currently reported amounts of the
group’s assets and liabilities and on similar
assets and liabilities that may be recognized
in the future.
Reviewed policy and guidelines for
compliance with oil and gas reserves
disclosure regulation, including the group’s
reserves governance framework and controls.
Reviewed the group’s oil and gas price
assumptions.
Reviewed the group’s discount rates for
impairment testing purposes.
Upstream impairment charges, reversals
and ‘watch-list’ items were reviewed as part
of the quarterly due diligence process.
The group’s price assumption for Brent« oil
and for Henry Hub«gas were revised
downward and the period covered extended
to 2050 as set out on page 28 and Note 1.
Sensitivity analyses estimating the effect of
changes in revenue and discount rate
assumptions have been disclosed in Note 1.
Significant impairments were recorded in the
year as a result of the lower price
assumptions as disclosed in Note 4.
Headroom on goodwill balances was
reduced (see Note 14 for further information).
Reviewed management’s best estimate
of oil and natural gas price assumptions for
value-in-use impairment testing.
Reviewed management’s assessment of
recoverability of exploration intangibles.
Received briefings on decommissioning
provisions.
Management’s revised best estimate of
oil and natural gas prices are broadly in line
with a range of transition paths consistent
with the goals of the Paris climate
change agreement.
Exploration write-offs were recognized as
a result of revised expectations to extract
value from certain exploration prospects
(see Note 8 for further information).
Reasonable changes in the expected
timing of decommissioning do not
have a significant impact on the
associated provisions.
98
bp Annual Report and Form 20-F 2020
Corporate governance
Key judgements and estimates
in financial report
Impact of COVID-19
Audit committee activity
Conclusions/outcomes
The following areas involving judgement and
estimates were identified as most relevant with
regard to the impact of the COVID-19 pandemic
and current economic environment: going
concern, discount rate assumptions, oil and
natural gas price assumptions, pensions and
other post retirement benefits, impairment of
financial assets measured at amortized cost
and income taxes.
Received briefings on COVID-19 impacts as
part of the quarterly due diligence process.
Reviewed liquidity forecast assessments.
performed to support the going concern
assertion.
Reviewed discount rates used for
impairment testing and provisions.
Reviewed management’s best estimate
of oil and natural gas price assumptions for
value-in-use impairment testing.
Investment in Rosneft
Judgement is required in assessing the level of
control or influence over another entity in which
the group holds an interest. bp uses the equity
method of accounting for its investment in
Rosneft and bp’s share of Rosneft’s oil and
natural gas reserves is included in the group’s
estimated net proved reserves of equity-
accounted entities.
The equity-accounting treatment of bp’s
19.75% interest in Rosneft continues to be
dependent on the judgement that bp has
significant influence over Rosneft.
Derivatives
Reviewed the judgement on whether the
group continues to have significant influence
over Rosneft.
Considered IFRS guidance on evidence of
participation in policy-making processes.
Received reports from management
which assessed the extent of significant
influence, including bp’s participation in
decision making.
bp continues to be resilient despite current
economic conditions. The committee is
satisfied with management’s assessment
that the group will continue to operate as a
going concern for at least 12 months from
the date of approval of the financial
statements.
Material impairment charges and
exploration write-offs were recognized in
the Upstream segment as a consequence
of price assumption changes. See Note 1
for further information.
bp’s CEO, Bernard Looney, was appointed to
the Rosneft board of directors in June 2020.
bp has retained significant influence over
Rosneft throughout 2020 as defined by IFRS.
See Note 1 for further information.
For its level 3 derivative financial instruments,
bp estimates their fair values using internal
models due to the absence of quoted market
pricing or other observable, market-
corroborated data. Judgement may be required
to determine whether contracts to buy or sell
commodities meet the definition of a
derivative, in particular LNG« contracts.
Received regular reports on derivative
accounting judgements.
Received a briefing on the group’s trading
risks and reviewed the system of risk
management and controls in place.
Reviewed the control process and risks
relating to the trading business.
bp considers that contracts to buy or
sell LNG do not meet the definition of
a derivative under IFRS. bp has assets
and liabilities of $6.4 and $5.3 billion
respectively, recognized on the balance
sheet for level 3 derivative financial
instruments at 31 December 2020 mainly
relating to the activities of the trading
and shipping function.
bp’s use of internal models to value
certain of these contracts has been
disclosed in Note 30.
bp Annual Report and Form 20-F 2020
99
Corporate governance continued
Safety and sustainability committee
Chair’s introduction
I am pleased to present my second report as
chair of the SASC. During 2020, the committee
continued to work with the bp leadership team
to promote safe and reliable operations within
the organization.
Operational risk management remained a key
area of focus during 2020, against the challenging
backdrop of the COVID-19 pandemic with the
result that bp maintained a good safety record
during the year despite these challenges. The
committee (together with other non-executive
directors) conducted a virtual visit of bpx energy
Permian assets in December 2020. We were
very impressed with the safety culture and
performance demonstrated by the bpx energy
colleagues with whom we interacted during this
virtual visit, and we look forward to being able
to conduct a physical visit in due course.
As part of the review by the board of its
governance framework, the committee was
renamed as the safety and sustainability
committee with effect from 1 January 2021.
The committee’s remit has also been expanded
to include monitoring the effectiveness of the
implementation of bp’s sustainability frame. This
is an important step in light of bp’s new purpose
and ambition and I look forward to continuing to
work with the bp leadership team in furtherance
of the new purpose, underpinned by safety
and sustainability.
Nils Andersen stepped down from the
committee and the board in March 2020. I would
like to thank him for his valuable contribution and
commitment to the committee and I welcome
Johannes Teyssen as a new member of the
committee from the beginning of 2021.
Melody Meyer
Committee chair
Committee overview
Role of the committee
The role of the safety and sustainability committee
(SASC) (previously called the safety, environment and
security assurance committee, until 31 December
2020) is to look at the processes adopted by bp’s
executive management to identify and mitigate
significant non-financial risk. This includes monitoring
the management of personal and process safety
risk, security and environment risks and receiving
assurance that processes to identify and mitigate
such non-financial risks are appropriate in their
design and effective in their implementation.
Key responsibilities during 2020
The committee receives specific reports from the
business segments and functions, which include, but
are not limited to, the safety and operational risk
function, shipping, internal audit and group security.
The SASC can access any other independent advice
and counsel it requires on an unrestricted basis. The
SASC and audit committee worked together, through
their chairs and secretaries, to ensure that agendas
did not overlap or omit coverage of any key risks
during the year.
Meetings and attendance
There were six committee meetings in 2020. All
directors attended every meeting for which they were
eligible. In addition to the committee members, all
SASC meetings were attended by the CEO, the SVP
for safety and operational risk (S&OR) and the SVP
internal audit and/or his delegate. The EVP legal also
attended some of the meetings. At the conclusion of
each meeting the committee scheduled private
sessions for the committee members only, without
the presence of executive management, to discuss
any issues arising and the quality of the meeting. The
CEO receives invitations to join the private meetings
on an ad hoc basis and at least once a year the SVP
internal audit is invited to a private meeting with
the committee.
Membership
Melody Meyer
Nils Andersen
Member since May 2017
and chair since November
2019
Member (resigned March
2020)
Professor Dame
Ann Dowling
Member
Sir John Sawers
Member
The committee continued to
work with the bp leadership
team to promote safe and
reliable operations.
Melody Meyer
Committee chair
100
bp Annual Report and Form 20-F 2020
Activities during the year
System of internal control
and risk management
The review of operational risk and performance
forms a large part of the committee’s agenda.
Internal audit provided quarterly reports on its
assurance work and its annual review of the
system of internal control and risk management.
The committee also received regular reports
from the CEO and SVP S&OR on operational
risk, including regular reports prepared on the
group’s health, safety, security and environmental
performance and operational integrity. These
included meeting-by-meeting measures of
personal and process safety, environmental and
regulatory compliance, security and cyber risk
analysis, as well as quarterly reports from internal
audit. In addition, the SVP, internal audit regularly
met in private with the chair and other members
of the committee over the course of the year.
During the year the committee received separate
reports on bp’s management of risks relating to:
The committee reviewed these risks and
their management and mitigation in depth with
relevant executive management. The committee
reviewed the 2020 forward programme for the
internal audit function. The committee supported
the remuneration committee in relation to
remuneration policy.
Virtual site visit
In December 2020 the members of the
committee (together with the non-executive
directors of the board) made a virtual visit to the
bpx energy Permian site. Discussions during this
visit covered a broad range of bpx energy health,
safety and environment matters and provided an
opportunity for effective virtual engagement with
bpx energy staff.
Corporate reporting
The committee oversaw the bp Sustainability
Report 2019. The committee reviewed the
content and worked with the external auditor
with respect to its limited assurance of selected
sustainability KPIs.
Marine
Wells
Pipelines
Explosion or release at our facilities
Major security incidents
Cyber security (process control networks)
Corporate governance
bp Annual Report and Form 20-F 2020
101
Corporate governance continued
Geopolitical committee
Committee overview
Role of the committee
The committee monitors the company’s identification
and management of geopolitical risk.
Key responsibilities
Monitor the company’s identification and
management of major and correlated geopolitical
risk and consider reputational as well as financial
consequences.
Review bp’s activities in the context of political and
economic developments on a regional basis and
advise the board on these elements in its
consideration of bp’s strategy and the annual plan.
Major geopolitical risks are those brought about by
social, economic or political events that occur in
countries where bp has material investments.
Correlated geopolitical risks are those brought
about by social, economic or political events
that occur in countries where bp may or may
not have a presence but that can lead to global
political instability.
Meetings and attendance
The chairman and CEO regularly attend committee
meetings. The chief executive of Alternative Energy
and executive vice president, regions and the head
of government and political affairs attend meetings
as required. The committee met three times during
the year. All directors attended each meeting that
they were eligible to attend, with the exception of
Sir Ian Davis who missed one meeting due to a
prior commitment.
Membership
Sir John Sawers
Nils Andersen
Sir Ian Davis
Member since
September 2015 and
chair since April 2016
Member (resigned
March 2020)
Member (resigned
December 2020)
Melody Meyer
Member
Chair’s introduction
I am pleased to report on the work of the
geopolitical committee in 2020. The committee’s
agenda developed and evolved during the year,
reflecting a year with a significant number of
geopolitical developments globally.
Following changes to the board governance
framework that took effect on 1 January 2021,
the committee was replaced by a geopolitical
advisory council. Although the council is not a
formal committee of the board, its membership
includes other directors, certain members of the
bp leadership team and three external advisors,
with myself as chair. The geopolitical highest
priority risk is now overseen by the board as a
whole, informed by feedback from the council.
Sir John Sawers
Committee chair
Activities during the year
Early in the year, the committee considered the
potential impact on bp of policies and plans of the
new EU Commission and new UK government
elected in December 2019. Later in the year, the
committee considered the geopolitics of the
COVID-19 pandemic and its impact on
businesses and policies. The impacts of different
potential outcomes of the November US election
were discussed by the committee at its meeting
in September 2020. The committee also received
periodic geopolitical updates on a number of
territories in which bp has significant interests
throughout the year.
The committee’s agenda
developed and evolved during
the year, reflecting a year with a
significant number of geopolitical
developments globally.
Sir John Sawers
Committee chair
102
bp Annual Report and Form 20-F 2020
Directors’ remuneration report
Chair’s letter
Contents
Alignment with strategy
2020 performance and pay summary
2018-20 performance share plan outcome
Executive directors’ pay for 2020
Wider workforce in 2020
Stewardship and executive director interests
Non-executive director outcomes and interests
Other disclosures
Policy implementation for 2021
108
110
111
113
115
118
121
123
124
The committee wishes to place
on record our gratitude for all that
bp’s people achieved last year,
and our acknowledgment of the
challenging environment they
faced. We look forward to better
days ahead.
Paula Rosput Reynolds
Committee chair
Corporate governance
Dear shareholder,
Last year was enormously challenging – for the
world and for bp. Yet the bp team operated safely
and reliably, ran the business as well as could
possibly be expected, and launched a strategic
transformation of the company.
That bp achieved so much last year is a credit to
everyone in the company – from the leadership
to the front lines. Together, they delivered the
energy the world needs, and positioned the
company for the future.
Nevertheless, as COVID-19 took its toll around
the globe, there were consequences for bp’s
financial outcomes in 2020. The remuneration
committee always seeks to align employee
reward with shareholder experience. Thus,
despite extraordinary efforts on the part of the
organization, we decided that there should be
no 2020 pay-out for all those who normally
participate in our broadly-applicable annual
bonus plan.
We know that this decision was painful for bp’s
people, many of whom count on earning a cash
bonus as part of their personal and family
financial planning. While words cannot substitute
for remuneration not received, the committee
wishes to place on record our gratitude for all that
bp people achieved amidst the environment they
faced. We look forward to better days ahead.
Shareholder engagement
Throughout this challenging period when we had
many decisions to make regarding metrics and
reward, the committee has benefited from
engagement with our shareholders. The
remuneration policy under which we now operate
was directly shaped by a meeting we held with
bp’s top 25 shareholders and other proxy
representatives in 2019. We appreciated
shareholders’ overwhelming support (96.58%
approval) of the new policy at our AGM last May.
Throughout 2020, we have continued to meet
(virtually) with our largest shareholders to discuss
a range of performance and incentive topics in
detail. We are grateful for your counsel and hope
you will see your advice reflected in the decisions
which we have reached. We ask for your support
of this directors’ remuneration report, and the
decisions described herein, at the forthcoming
annual general meeting.
bp Annual Report and Form 20-F 2020
103
Directors’ remuneration report continued
In this report, the committee continues its
practice of scrutinizing both one- and three-year
performance. Even in the absence of paying
annual bonuses for 2020, we have included some
discussion on results to give a balanced view of
what worked well and what disappointed. This
report covers our decisions for 2020 and the
details regarding our implementation of the 2020
remuneration policy for 2021 and beyond. The
highlights are provided immediately below.
Key remuneration outcomes for 2020
No pay-out under our 2020 annual bonus plan.
There was no pay-out under the annual bonus
plan for any of the participating employees
Lower vesting for the 2018-2020 equity plan.
The vesting outcome for our 2018-20
performance shares cycle is 32.5% of
maximum, down from 71.2% in the previous
cycle, and from an average of over 66% over
the last six cycles. It is worth noting that the
committee made no alterations to the
performance measures or targets on which
these awards were based, nor any
discretionary adjustment to the vesting
outcome. This vesting outcome applies equally
to our former executive directors, and to our
new CEO and CFO in respect to their pre-
appointment performance share awards.
Key remuneration decisions
for 2021 and beyond
To recognize the efforts of the wider
workforce, virtually all employees will receive
an above-market pay increase in 2021. Large
numbers of our employees received no pay
adjustment in 2020 or had their increase
deferred for six months. Given the large
reduction in headcount and all the responsibility
this action places on those who remain, we
agreed with management’s plan to increase
salaries across-the-board, and ahead of market.
Any time salaries rise, the cost of other
remuneration that hinges off salary rises as
well. At the same time, we are obligated to
monitor disparate impacts and overall welfare
of the workforce. We will, therefore, continue
to monitor and balance the costs of the
programme with wider workforce pay issues.
We considered the approach to salary for our
executive directors apart from the wider
workforce. We embrace restraint as a guiding
principle, but restraint must be balanced with
fair reward for contribution. The board has
been gratified by the immediacy of Bernard
Looney’s impact in leading the organisation,
and in refreshing bp’s purpose, strategy and
organisation. We propose to recognize his
efforts with an increase of 2.75% salary with
effect from the annual general meeting. This
increase is significantly lower than the increase
that our UK professional workforce will receive
on their pay review date in 2021.
Murray Auchincloss has likewise made an
immediate impact since his appointment. He
fully assumed the challenges of the CFO role
and has forged a strong partnership alongside
Bernard. We set his initial salary in 2020 at a
level below comparable rates for finance
directors in the FTSE 30, until we could be
certain of the contribution he would bring to
the role. Shareholders will recall our policy is to
keep executive increases within the boundary
of wider workforce increases, except in
specific circumstances. We find that Murray is
already contributing beyond our expectations
of even a seasoned CFO. Given his criticality to
the execution of our strategy, we conclude that
adjusting his below-market salary is such a
specific circumstance. We therefore intend to
increase his salary by 8% to £750,500,
following the annual general meeting, placing
him in line with the median rate for FTSE 30
CFOs. It is our intention, subject to the
committee’s view of Murray’s continued
development and success in role, to bring his
salary in line with that of his predecessor and
other CFOs in similarly challenging roles. We
anticipate that this may require increases
somewhat above the wider workforce average
in the future.
In 2021 we have made an all-employee share
award to allow employees to participate in the
success that a reinvented bp can deliver. The
majority of employees will receive restricted
shares vesting in 2025, while more senior
employees will receive share options to be
exercised from 2025 onward and with a
ten-year term.
We are bringing our metrics and targets for
both the 2021 annual bonus and the 2021-23
performance share into line with bp’s new
strategy and the refreshed commitments to
financial performance. The changes are
described in detail in this report and we hope
you will see how closely we have sought to
align these targets to the commitments that
management have articulated to investors.
The 2021-23 awards will be in line with
approved policy and the grant size is
unchanged from prior years. All share awards
will be granted after the annual meeting and
pricing will be based on the preceding 90 days.
Overview of financial performance,
operating achievements, and
strategic progress
Our 2020 annual bonus plan consisted of
measures associated with financial performance
and operations. Our long-term share plan
consisted of financial measures and strategic
progress. Each area of performance is
summarized below to provide a sense of how
we evaluated overall performance.
Financial performance for bonus purposes was
measured in terms of underlying replacement
cost profit and free cash flow. For performance
shares, we measured return on average capital
employed (ROACE) and relative total shareholder
return (rTSR). In neither the short nor the
long-term plan did actual financial performance
meet targets.
Over the three-year performance period,
however, bp ranked third out of the five super-
majors for rTSR purposes which accounted
for a modest 12.5% vesting of the 2018-20
performance share grant. To offer some
perspective, we note that during 2020 the
company reduced net debt by $6.5 billion to $39
billion. In announcing the sale of a share of bp’s
interest in Oman’s Block 61, we continue making
good progress towards the 2025 target of $25
billion of proceeds from divestments. Importantly,
too, management initiated the review of bp’s
portfolio of assets in 2020 and recommended
significant impairments and exploration write-
offs. Thus, management took the necessary
steps to address the value of our assets given
the energy transition, in full knowledge that they
would forego near-term benefit because of these
actions. We think this reflects well on the system
of reward – not paying when performance is
below expectations – but also on the integrity
of the leadership which is nonetheless doing
the right thing to create a sustainable future.
104
bp Annual Report and Form 20-F 2020
Corporate governance
Despite the challenges of the pandemic,
operations were strong in 2020, with refining
availability of 96%, upstream plant reliability of
94%, and delivery of four new major projects.
Safety trends were also positive, with process
safety events, recordable injury frequency, and
other key safety and environmental metrics
significantly lower than in 2019. While workforce
hours were down, bp people safely managed
increased COVID-19-related risks and travel
restrictions, and increased quarantine periods
associated with cross-border crew rotations,
while ensuring safety critical staffing and
emergency response preparedness. bp teams
also delivered above-target sustainable emissions
reductions in 2020.
Strategic progress is the other area we assessed;
in the 2018-20 performance share plan it carried a
20% weight.
As we consulted with shareholders, we can
appreciate that the inclusion of ‘strategic
progress’ in a scorecard can be a double-edged
sword. On the one side, measuring strategic
progress more specifically aligns our strategy
and the reward we will confer. On the other side,
strategic progress does not always carry with it
straightforward metrics that are more typically
used in remuneration designs. Thus the
committee must use its judgement and explain
its rationale. We do so here on page 111. We
hope you will agree that we’ve been thoughtful in
evaluating the organization’s strategic
performance over the 2018-20 period.
Other decisions and
forward-looking activity
In our approved 2020 remuneration policy,
we retained flexibility to adjust performance
measures and weightings in both our annual
bonus and performance share plans. Given the
shift in the business mix and the exigencies of
our financial frame, for the 2021 annual bonus,
we are introducing two new financial measures:
cumulative cash cost reductions (weighted at
25%); and an operational measure to reflect
margin share from convenience retail and
electrification (weighted at 10%). These changes
represent the committee’s best judgment for
fine-tuning measures to the new strategy. While
we are adding two new measures, we will
continue to measure annual performance of our
operations, of cash generation, of sustainable
emissions reductions and of safety.
For the 2021-23 performance share awards,
we will introduce an earnings per share growth
(EBIDA CAGR) measure alongside the existing
ROACE measure (each weighted at 20%), and
will reduce the weighting on rTSR (from 40% to
20%). Many of you will recall that the relevance
of rTSR and the selection of an appropriate peer
group were widely, but inconclusively discussed,
during our September 2019 stakeholder
engagement session. Against that backdrop, our
judgment is that if the bp team can achieve the
multi-year financial results to which it committed
in July 2020, then the team should be rewarded,
with only a modest calibration to what other
energy companies accomplish over these
three years.
Remuneration committee
Role of the committee
The role of the committee is to determine and
recommend to the board the remuneration
policy and to set chair, executive director and
leadership team remuneration. It reviews
workforce remuneration and monitors related
policies, satisfying itself that incentives and
rewards are aligned with bp’s culture. In
determining the policy, the committee takes
into account various factors, including workforce
remuneration, and structures the policy to
promote the long-term success of the company
and linking reward to performance.
Key responsibilities
Recommend to the board the remuneration
principles and policies for the executive
directors while considering remuneration
and related policies for employees below
the board and the executive team.
Set and approve the terms of engagement,
remuneration, benefits and termination of
employment for the executive directors,
leadership team and the company secretary
in accordance with the policy.
Prepare the annual remuneration report to
shareholders to show how the policy has
been implemented.
Approve the principles of any equity plan
that requires shareholder approval.
Ensure termination terms and payments
to executive directors and leadership team
are fair.
Receive and consider regular updates on
workforce views and engagement initiatives
related to remuneration, insight from data
sources on pay ratio, gender pay gap and
other workforce remuneration outcomes
as appropriate.
Maintain appropriate dialogue with
shareholders on remuneration matters.
Membership
Paula Rosput Reynolds Member since
Nils Andersen
Pamela Daley
Sir Ian Davis
Melody Meyer
September 2017 and
chair since May 2018
Member (resigned
March 2020)
Member
Member (resigned
30 December 2020)
Member since
March 2020
Brendan Nelson
Member
Meetings and attendance
The chairman and the CEO attend meetings of
the committee except for matters relating to
their own remuneration. The CEO is consulted
on the remuneration of the CFO, the leadership
team and more broadly on remuneration across
the wider employee population. Both the CEO
and CFO are consulted on matters relating to
the group’s performance.
bp’s EVP people and culture, SVP reward and
wellbeing and advisors attend meetings and
other executives may attend where necessary.
The committee consults other board
committees on the group’s performance and
on issues relating to the exercise of judgement
or discretion as necessary.
The committee met nine times during the year.
All directors attended each meeting that they
were eligible to attend, except Sir Ian Davis who
was not able to attend two meetings, and
Pamela Daley and Brendan Nelson who each
missed one committee meeting.
bp Annual Report and Form 20-F 2020
105
In this directors’ remuneration report RC profit
(loss), underlying RC profit, return on average
capital employed, operating cash flow
excluding Gulf of Mexico oil spill payments,
margin share for convenience and
electrification, net debt and cumulative cash
cost reductions are non-GAAP measures.
These measures, together with upstream
plant reliability and refining availability,
are defined in the Glossary on page 341.
Directors’ remuneration report continued
Also noteworthy for the 2021-23 performance
share awards, we are recasting the strategic
progress measures to three well-defined areas:
(1) delivering value through a resilient and focused
hydrocarbon business; (2) building scale and
value through investments in lower carbon
electricity and energy sources; and (3)
accelerating growth in convenience and mobility.
Strategic progress metrics will be weighted at
40%. Several shareholders have asked us to be
more specific about which measures from the
September 2020 presentations we intend to
use in evaluating strategic progress, and I say
more on this at page 109 in the alignment to
strategy section.
The leadership team has been bold in seeking
to transform bp and has shown exemplary
cooperation in developing these challenging
performance measures.
Wider workforce and activities
through the pandemic
Much of the committee’s time this year was
dominated by the pandemic, which had a serious
impact on workforce and remuneration matters.
With our plans to reinvent bp already proceeding
when the pandemic hit, bp’s leadership
committed that no redundancies would take
place for a minimum of three months to allay
immediate concerns about job security. Also, bp
sought no pandemic relief in the form of grants
or furlough funding from any governments
anywhere in the world.
Despite the limited ability to meet in person,
the committee and the board engaged with
employees virtually throughout the year. Despite
the fact that 2020 was a year with many
discouraging moments, we find that the
employees are highly engaged – and willing
to speak their minds – which bodes well for
the future.
From the outset of the pandemic’s impact,
mental health as well as physical well-being were
of concern. Both Bernard and our chair Helge
Lund donated 20% of their salaries to charities
dealing with mental health issues from April
2020. In addition, Bernard directed the company
to make a substantial donation to the UK mental
health charity, Mind. This generosity is consistent
with the leadership’s support for mental health
within the company, and given the duration and
far-reaching effects of the pandemic, was
exceptionally far-sighted.
Closing thanks
Following their retirement from the board,
I thank Nils Andersen and Sir Ian Davis for their
many contributions to this committee, while
welcoming Melody Meyer and, most recently,
Tushar Morzaria.
At the annual general meeting, Brendan Nelson
plans to stand down and his particular brand
of sober judgement will be greatly missed by
the committee.
The technology we have all deployed in the last
year has only served to enhance our consultation
with shareholders and their advisors. These
virtual face-to-face contacts from our respective
homes have allowed for frequent conversations.
We thank you for fitting us into your long days,
and as you review the details provided in this
report, we welcome your comments.
Paula Rosput Reynolds
Chair of the remuneration committee
22 March 2021
106
bp Annual Report and Form 20-F 2020
Remuneration at a glance
Salary and benefits
Retirement benefits
Annual bonus
Performance shares
Corporate governance
Purpose and key features
Outcomes for 2020
Implementation in 2021
Fixed remuneration reflecting the
scale and complexity of our
business, enabling us to attract and
keep the highest calibre global
talent.
Reviewed annually and, if
appropriate, increased following
the AGM.
Benchmarked to market at inception
with increases limited to those of
our wider workforce, except in
specific circumstances.
To recognize competitive practice in
home country.
Bernard is a deferred member of a
UK final salary pension plan, but now
receives a cash allowance in lieu of
retirement benefits.
Murray is a deferred member of a
US final salary pension plan, but now
receives a cash allowance in lieu of
retirement benefits.
Bob was a member of both a US
final salary pension plan and a US
retirement savings plan.
Brian was a member of a UK final
salary pension plan and received a
cash allowance in lieu of further
service accrual.
To incentivize delivery of our annual
and strategic goals.
112.5% of salary at target, and 225%
at maximum.
To reinforce the long-term nature of
our business and the importance of
sustainability, 50% of the bonus is
paid in cash and 50% is mandatorily
deferred and held in bp shares for
three years.
To align reward to our strategy and
long-term performance. Vesting
outcomes vary relative to our
financial returns and strategic
priorities.
Annual grant of performance shares,
representing the maximum
outcome. 500% of salary for the
chief executive officer and 450% of
salary for chief financial officer.
Bernard Looney’s salary set at
£1,300,000 on appointment.
Murray Auchincloss’s salary set at
£695,000 on appointment.
Bob Dudley’s salary unchanged at
$1,854,000 until cessation.
Brian Gilvary’s salary unchanged at
£790,500 until cessation.
Benefits were unchanged.
Bernard has no further service
accrual for his deferred pension, and
the pension calculation will be based
on his pre-appointment salary.
His cash allowance is fixed at 15%
of salary.
Murray has no further service
accrual for his deferred pension
arrangement, and the pension
calculation will be based on his
pre-appointment salary. His cash
allowance is fixed at 15% of salary.
Bob’s defined benefit pension did
not increase in 2020. bp actual and
notional retirement savings plan
contributions of $32,445 were more
than offset by investment losses
within his plans, hence he received
no net benefit in 2020.
Brian’s defined benefit pension
increase was below inflation. His
cash allowance was 30% of salary to
30 May, and 25% of salary from
1 June 2020.
No bonus for 2020.
Awards granted in 2018 (under our
2017 policy) were assessed against
our balanced scorecard of financial
(80%) and strategic progress (20%)
measures. Our 2018-20
performance share outcome is
32.5% of maximum vesting.
Bernard’s salary to increase
by 2.75% to £1,335,750 from
the AGM.
Murray’s salary to increase by 8%
to £750,500 from the AGM.
Benefits to remain unchanged.
Bernard’s cash allowance will be
unchanged at 15% of salary, and
he accrues no further value under
his deferred pension.
Murray’s cash allowance will be
unchanged at 15% of salary, and
he accrues no further value under
his US deferred pension.
For our 2021 bonus, our scorecard
will be reweighted to safety (15%),
environment (15%), operational
(20%) and financial (50%), as
described on page 125.
Awards granted in 2019 (under our
2017 policy) will vest in proportion
to success against the measures
of our 2019-21 scorecard.
For the 2021-23 cycle (under our
2020 policy), grant levels will
remain unchanged at 500% for
Bernard and 450% for Murray,
with weightings of 20% each for
rTSR, ROACE and EBIDA CAGR,
and 40% for strategic measures,
as shown on page 125.
The minimum shareholding
requirements remain unchanged.
Shareholding requirement
To ensure sustained alignment
between shareholder and executive
director interests.
The chief executive officer and other
executive directors are required to
maintain shareholdings equivalent to
500% and 450% of salary
respectively, including for two years
post employment (2020 policy).
Both former executive directors
materially exceed their post-
employment share ownership
requirements of two and a half times
salary (pre-dating the 2020 policy).
Bernard and Murray have not yet
achieved their minimum shareholding
requirement (they must do so within
five years of appointment).
bp Annual Report and Form 20-F 2020
107
Directors’ remuneration report continued
Alignment with strategy
The frame for our remuneration
policy and practice
Last year we refreshed our remuneration policy
following wide consultation, individually and
collectively, with shareholders. Through that
consultation we decided to retain the strongly
performance-oriented reward model that served
us well in the previous decade. Thus, we retained
and built upon the established policy structure,
with the advantage this brings of being well-
understood and accepted by our executives and
wider workforce alike.
bp’s purpose, ambition and strategy
bp’s purpose, to reimagine energy for people and
our planet, is complemented with a clear and
unambiguous ambition – to be a net zero
company by 2050 or sooner and to help the world
get to net zero. Our strategy is transformational,
to pivot from International Oil Company to
Integrated Energy Company, from a focus on
developing resources, to a focus on delivering
solutions for customers. As seen below, this
strategy is grounded in three focus areas and
three sources of differentiation, set within a
sustainability frame linking our strategy to
our purpose.
By design, this refreshed policy allows for
ongoing alignment to the nearer-term needs of
our strategy, with measures intended to evolve
in line with the pace and form of the energy
transition. This design reflected the four broad
themes that emerged from our engagement
with shareholders:
A clear end-to-end alignment from strategy,
through measurable performance indicators
and reward outcomes, to shareholder
experience.
To balance our contribution to the energy
transition with delivering shareholder returns,
with encouragement to use appropriate
discretion given the complexity of the
environment in the energy transition.
To ensure strategic measures align to
long-term sustainability, relative to a wide
peer group.
To use meaningful and transparent
performance indicators reflecting our progress
in the energy transition and reductions to our
carbon impact.
Connecting remuneration to strategy
Alignment with strategy is evident in:
Clearly measurable safety, sustainability,
strategic and financial measures for each cycle
of annual bonus and/or performance shares.
The judgements we make to assess qualitative
progress against strategic objectives.
Our ‘underpin’ assessment to take safety
outcomes into account prior to determining the
final performance shares vesting percentage.
Our overarching discretionary decisions to
ensure share plan outcomes reflect
shareholder experience, environmental,
societal, and other inputs.
Achieving balance between safety, sustainability,
strategic and financial measures is an essential
consideration for the committee in applying
policy. Considering the three ‘focus areas’ of bp’s
strategy, generating cash from our resilient and
focused hydrocarbons business is the critical
element to support bp’s transition into the two
growth areas – low carbon electricity and energy,
and convenience and mobility. We expect bp to
be directing 40% or more of its investment into
these areas by 2030, but that reallocation of
spend will be a gradual and non-linear matter,
requiring flexibility and judgement from
leadership. Our commitment is to oversee this
transition with care, applying remuneration policy
to incentivize results in the most critical areas.
In our most recent consideration we have
therefore aligned the strategic performance
measures of our 2021-23 performance share
awards entirely to the three ‘focus areas’ of bp
strategy: low carbon electricity and energy;
convenience and mobility; and resilient and
focused hydrocarbons. This means that, for now,
we are consciously not introducing measures
related to the three ‘sources of differentiation’, in
the belief that we need to limit the total number
of measures and highlight those which are the
most pressing.
This has also led us to review our decision-
making from last September when we set
strategic measures for the 2020-22 performance
share awards. At that time, we had chosen four
strategic elements – two of the focus areas, and
two of the sources of differentiation. With the
hindsight of our more recent discussions and a
deeper understanding of how the strategy is
likely to yield most value, we realise those earlier
decisions were not the best. Therefore, we are
taking the unusual step of amending our 2020-22
strategic progress measures mid-cycle, to align
them instead with the measures of our 2021-23
cycle. Thus we bring focus to the most critical
areas, align the measures for the first two cycles
of share award under our 2020 policy, and can
develop a common set of performance metrics
that will allow us to transparently report progress
across all three cycles of award under the 2020
policy (ie. those starting in 2020, 2021 and 2022).
The table on page 109 summarizes the alignment
between performance measures and strategy,
showing the weightings associated with each.
Low carbon
electricity
and energy
Convenience
and mobility
Resilient
and focused
hydrocarbons
Integrating energy systems
Partnering with countries, cities and industries
Driving digital and innovation
A sustainability frame
linking our purpose and
108
bp Annual Report and Form 20-F 2020
Corporate governance
Aligning performance measures and strategy
Safety, our core value
Low carbon
Convenience and mobility
Resilient hydrocarbons
Integrating energy
Partnering
Digital
Sustainability
Financial frame
2020
annual bonus
2021
annual bonus
2020-22
performance shares
2021-23
performance shares
20%
–
–
10%
–
–
–
20%
15%
–
10%
10%
–
–
15%
Underpin
Underpin
30%{
{
40%
–
–
–
–
–
–
–
–
25% cash flow
25% profit
25% cash flow
25% cumulative
cash cost reduction
40% rTSR
30% ROACE
20% rTSR
20% ROACE
20% EBIDA CAGR
Looking forward, strategic progress for the 2020-22 and 2021-23 performance shares will be a largely qualitative assessment by the committee, supported
by key performance indicators that will enable us to add a quantitative overlay in our assessments and to allow reporting on progress through the concurrent
cycles of each award. These indicators are as follows:
Resilient and focused hydrocarbons
Production costs per barrel: track
improvement in unit production cost per barrel
to help deliver margin efficiency.
Plant reliability: measure the reliability of
upstream production assets as an indicator of
operational efficiency.
Refining availability: measure the availability
of downstream refining assets, also as an
indicator of operational efficiency.
Demonstrate track record, scale
and value in low carbon electricity
and energy
Gigawatts of developed renewables
energy: confirm the growth and value added
from new renewable energy projects.
Clear decisions on other energy platforms:
demonstrate strategic progress in the selection
of energy platforms for future growth.
Renewables pipeline: build a renewable
pipeline in alignment with 2025 and 2030 goals
while consistent with targeted returns.
Accelerate growth in convenience
and mobility
Castrol performance: demonstrate growth
momentum in Castrol.
Strategic convenience sites: confirm the
number of strategic convenience sites.
Margin share from convenience and
electrification: demonstrate the capture of
growth from the energy transition through the
retail network via measuring the ratio of
convenience and electrification gross margin
to total consumer energy (retail fuels and
electrification) and convenience gross margin.
bp Annual Report and Form 20-F 2020
109
Directors’ remuneration report continued
2020 performance and pay outcomes
Business
performance
An exceptional year of challenge and internal reinvention
Key strategic highlights
Completed the Southern Gas Corridor pipeline system, with the
Trans Adriatic pipeline beginning gas deliveries.
Agreed to sell our petrochemicals business to INEOS.
Added ~300 strategic convenience sites across our retail network,
bringing the total to 1,900.
3rd
Among peers for
total shareholder
return 2018-20
$13.8bn
Operating cash
flow excluding Gulf
of Mexico oil spill
payments
$6.4bn
Total dividends paid
to shareholders
Performance
outcomes
Robust safety and operating outcomes, but plan unaffordable.
Strong strategic progress, weak financials.
2020 annual bonus
No bonus
Formulaic outcome
(% of maximum)
n/a
Committee
judgement
2018-20 performance shares
n/a
Final outcome
(% of maximum)
32.5%
Formulaic outcome
(% of maximum)
0%
Committee
judgement, no
adjustment
32.5%
Final outcome
(% of maximum)
KPI
Performance dimensions (% weighting)
Performance dimensions (% weighting)
This legend denotes
remuneration measures
that directly relate to bp’s
key performance indicators.
See page 39.
Safety (20%)
Environment (20%)
Operational (10%)
Financial (50%)
No bonus for 2020
Financial (80%)
Strategic progress (20%)
KPI
KPI
12.5/80
20/20
Annual bonus outcome (% of maximum)
Performance shares outcome (32.5% of maximum)
Bernard Looney
Nil
Murray Auchincloss Nil
Nil
Bob Dudley
Nil
Brian Gilvary
Bernard Looney
Murray Auchincloss
Bob Dudley
Brian Gilvary
£0.35m
£0.22m
$1.57m
£0.62m
Total
remuneration
2020
See page 113
for detail.
Bernard Looney
CEO from 5 February 2020
Murray Auchincloss
CFO from 1 July 2020
Bob Dudley
CEO to 4 February 2020
Brian Gilvary
CFO to 30 June 2020
1.
1.
1.
1.
4.
2.
£1.74m
2019: n/a
4. £0.62m
2019: n/a
2.
$0.19m
2019: $13.3m
2.
£0.55m
2019: £6.6m
1. Salary and benefits
2. Retirement benefits
3. Annual bonus
4. Performance shares
Share
ownership
Shareholding is a key means by which the interests of executive directors are aligned with those of shareholders. The CEO and CFO shareholdings
are shown below, as at 2 March 2021. Both these new executive directors are building towards the policy requirement, which is mandatory within
five years of appointment.
Bernard Looney, CEO
Murray Auchincloss, CFO
Policy requirements
Actual
1.24 times salary, 543,939 shares
0.60 times salary, 141,535 shares
110
bp Annual Report and Form 20-F 2020
Corporate governance
2018-20 performance share plan outcome
Vesting under our performance share plans is assessed using the group
performance scorecard shown on page 112, and subject to any discretionary
adjustment by the committee. Bernard and Murray were granted 2018-20
performance share awards under the Group Share Value Plan (GSVP) for bp
group leaders, rather than under the Executive Director Incentive Plan
(EDIP). The GSVP and EDIP both use the same scorecard, therefore the
comments in this section apply equally to our former and new executive
directors, as well as our group leaders, even though they relate to
performance shares awarded under different plans.
The financial outcomes for the three-year period were disappointing.
Return on average capital employed averaged 2.6% over 2019 and 2020
(the ROACE measurement period for this cycle), below our threshold level
for vesting on this measure. Total shareholder returns turned negative for
bp, alongside all our constituent peer companies. bp placed third among
our competitor group, however, which yielded formulaic vesting of 12.5%
(of a potential 50%). To counter the impact of share price volatility in TSR
measures, bp has continued its standard practice of averaging US market
prices over the fourth quarter immediately before, and at the end of, the
three-year performance cycle. Peers in our competitor group may use
different pricing methods, leading them to report different ranking
outcomes from bp.
As reported last year, we introduced four strategic progress measures in our
2017 policy, and this is now the second cycle for which we have made an
assessment on strategic progress. These were the measures that then
positioned bp for the future, and the committee found that in all four
strategic areas the business has delivered fully against intended outcomes.
Thus vesting on this element of the scorecard is determined to be 20%.
The key factors that formed our scoring decision were:
Growing gas and advantaged oil in the upstream. Gas production grew
from 1.11mmboed in 2017 to 1.15mmboed by 2020, with eight major gas
projects started up in the period. In the same period bp started up seven
major oil projects and have a further eight major oil projects under
construction. We purchased BHP tight oil assets, accessing some of the
best basins onshore in the US.
Market-led growth in the downstream. We have continued strategic
progress with our convenience partnership model now in around 1,900 sites
across the network, with 800 opened since 2017. The growth has been
driven by the roll-out of REWE to Go in Germany, our Thorntons business
in North America, and new partnerships launched in South Africa, Australia,
New Zealand and Portugal. Retail store gross margin has grown 6% per
annum since 2017 to over $1bn and is showing resilience despite COVID-19.
In growth markets, we doubled our retail sites to 2,700 in 2020, expanded
our network to over 500 bp-branded retail sites« in Mexico, and opened
over 1,400 sites in India with our Reliance joint venture. In our sustainable
aviation fuel business, we added 13 new locations to Air bp’s supply
network and have struck an innovative collaboration with Neste for supply
of sustainable aviation fuel. We have made a further $40 million investment
in Fulcrum since 2017.
Venturing and low carbon across multiple fronts. Lightsource bp now
has a presence in 14 countries, up from five in 2018. We have created a
differentiated strategy in electric vehicle charging through bp pulse and
Storedot, which has demonstrated five-minute charging capability. Our focus
on reducing emissions has progressed well, with a reduction from 48.8Mte
in 2018 to 41.7Mte in 2020, aligning with our net zero ambition. Our 2020
methane intensity is estimated at 0.12%, well below our target of 0.2%
Gas power and renewables trading and marketing growth. We remain
the largest US gas and power marketing company. In 2018 and 2019 we
added six advanced liquified natural gas (LNG) tankers to the bp-operated
fleet; our Tangguh LNG expansion started drilling in 2019; and Train 2 of our
Freeport LNG began commercial operations in 2020, with first gas deliveries
from bp under our 20-year tolling agreement.
Along with the combination of financial and strategic measures, the
committee considers an ‘underpin’ decision before deciding on the final
result, taking a broader view to ensure that the reward outcome aligns
with absolute shareholder returns, safety and environmental factors,
and low carbon and climate change considerations. The committee has
been mindful of the need to take an even broader perspective, and thus
consider executive outcomes in relation to societal matters in general and
our wider workforce in particular. While absolute returns disappoint, we
find that all aspects of the underpin support at least 32.5% vesting, which
from a participant’s perspective reflects a poor return for the efforts
expended. Therefore, our overall judgement is to leave the vesting
outcome unadjusted.
As mentioned above, this scorecard outcome applies to all participants in
both the EDIP (for executive directors) and the GSVP (for group leaders).
With time pro-ration for Bob and Brian to reflect their periods of service
during the three-year performance period, this vesting delivers the
outcomes detailed below. For Bernard and Murray these values are included
in the single figure table on page 113, whereas for Bob and Brian they are
reported in the payments for past directors section at page 122.
2018-20 performance share plan outcomes (audited)
Shares
awarded
158,690b
77,958b
1,395,600
696,705
Shares
vesting
including
dividends
Value of
vested
shares, Feb/
Mar 2021
Impact of
share price
changea
126,134
62,124
£350,652
$275,934
410,922 $1,566,298
£618,357
227,337
-£228,991
-$111,497
-$962,923
-£430,217
Bernard Looney
Murray Auchinclossc
Bob Dudleyc
Brian Gilvary
a These values reflect the impact of the reduction in share price since grant related to the number
of shares that vest, excluding dividend equivalents.
b Share grants under the GSVP are made at 50% of maximum, not at 100% of maximum as for
the EDIP.
c Bob Dudley and Murray Auchincloss’s awards were granted in respect of American depositary
shares (ADSs). The numbers in this table reflect calculated equivalents in ordinary shares. One
ADS equates to six ordinary shares.
The value of vested shares reflects the share price changes all shareholders
have experienced over the three-year period. For this 2018-20 award cycle,
the original grant was calculated based on ordinary share and American
depositary share (ADS) prices of £5.00 and $39.85 respectively, while the
values at vesting were £2.78/£2.72 (on 16 and 19 February respectively),
and $22.87/$26.65 (on 19 February and 10 March respectively).
Consequently, the share price fall has reduced the initial face value of these
awards by approximately 45% for ordinary shares, by 33% for Murray
Auchincloss’s ADSs, and by 43% for Bob Dudley’s ADSs. The committee
has made no discretionary adjustment to vesting outcomes related to these
share price changes.
bp Annual Report and Form 20-F 2020
111
See page 39 for more on our
key performance indicators.
Formulaic
vesting
32.5%
Outcome
Third
Directors’ remuneration report continued
2018-20 performance shares scorecard (audited)
These measures were set under the terms of our 2017 policy
Relative total
shareholder return
12.5%
+
Return on average
capital employed
0%
+
Strategic process
20.0%
=
Measures
Financial
Strategic
progress
Formulaic
Formulaic
vesting
32.5%
Relative total
shareholder return
Return on average
capital employed
Growing gas and
advantaged oil in
the upstream
Market-led growth
in the downstream
Venturing and low
carbon across
multiple fronts
Gas power and
renewables trading
and marketing growth
Weighting
at maximum
Threshold
performance
Maximum
performance
50%
Third
First
30%
7.375%
11.5%
2.6%
Outcome
12.5%
5%
5%
5%
5%
Qualitative and quantitative assessment
by the committee. No numeric scale for
vesting outcome.
See page 111
Outcome
20.0%
12.5%
0%
5.0%
5.0%
5.0%
5.0%
32.5%
Underpin: Committee review of absolute returns, long-term safety and
environmental performance, low carbon and climate change considerations:
No adjustment
Final vesting after
committee judgement
32.5%
112
bp Annual Report and Form 20-F 2020
Corporate governance
Executive directors’ pay for 2020
Single figure table – executive directors (audited)
Salary
Benefits
Retirement benefits
Cash in lieu of retirement benefits
Annual bonus, cash
Annual bonus, deferred (as detailed on page 107)
Performance shares (as detailed on page 107)
Discontinued plans
Total remunerationb
Total fixed remuneration
Total variable remuneration
Bernard
Looney CEO
since
5 Feb 2020
(thousand)
Murray
Auchincloss
CFO since
1 July 2020
(thousand)
2020
£1,181
£26
–
£177
–
–
£351
–
£1,735
£1,384
£351
2020
£348
£8
–
£52
–
–
£215
–
£623
£408
£215
Bob Dudley CEO to 4 Feb
(thousand)
Brian Gilvary CFO to
30 June (thousand)
2020
$170
$18
$0
–
–
–
–
–
2019
$1,854
$84
$544
–
$1,408
$1,408
$8,039a
–
$188
$188
$13,336
$2,481
$0
$10,855
2020
£395
£41
£0
£115
–
–
–
–
£552
£552
£0
2019
£785
£59
£0
£252
£600
£600
£2,787a
£1,529a
£6,612
£1,095
£5,517
Please refer to the overview section below for additional detail, except where noted otherwise.
a The amounts reported for 2019 have been adjusted to include the vesting of additional dividends on 5 November 2020 at the market price of £2.03 for ordinary shares and $15.83 for ADSs. See the
performance shares table on page 111, and the deferred shares table on page 120, for further details on these awards.
b Due to rounding, the totals do not agree exactly with the sum of their component parts.
Overview of single figure outcomes (audited)
Bernard Looney and Murray Auchincloss started in their roles as CEO and
CFO on 5 February and 1 July 2020 respectively. Accordingly, the values
shown in the single figure table represent remuneration outcomes from the
time of their appointment to the board only. Similarly, because Bob Dudley
and Brian Gilvary stepped down on 4 February and 30 June respectively,
their 2020 remuneration values relate only to their part-years of service as
executive directors. Payments received after they stepped down from their
position are included in the payments to past directors section on page 122.
Salary and benefits
Bernard Looney’s salary was £1,300,000 from appointment. The amount
reported above is before his 20% mental health charitable contribution.
Murray Auchincloss’s salary was £695,000 from appointment. Bob Dudley’s
salary remained at $1,854,000 until his exit on 31 March 2020. Brian
Gilvary’s salary was unchanged at £790,500 until his exit on 30 June 2020.
All executive directors received car-related benefits, assistance with tax
return preparation, security assistance, insurance and medical benefits.
2020 annual bonus
The committee concluded that there should be no bonus for 2020 as the
plan was unaffordable. There were no other contributing factors leading
us to this decision.
2018-20 performance shares
Please refer to page 112 for details of the performance measures,
targets and outcomes for these performance shares.
Retirement benefits
From their appointment as executive directors, Bernard Looney and Murray
Auchincloss ceased to receive any retirement benefits for their service, but
receive a cash allowance fixed at 15% of salary in line with the majority of
similarly situated employees. They may choose to direct these allowances
into retirement plans at their sole discretion, and the amounts are therefore
identified as cash in lieu of retirement benefits on the single figure table.
Bob Dudley was provided with pension benefits and retirement savings
through a combination of tax-qualified and non-qualified benefit plans. His
normal retirement age is 60. The BP Supplemental Executive Retirement
Benefit Plan (SERB) is a non-qualified defined benefit pension plan which
provides a proportion of earnings for each year of service. In 2020 his
accrued defined benefit pension did not increase, and the amount included
in the single figure table is therefore zero.
The BP Employee Savings Plan (ESP) is a US tax-qualified defined
contribution plan to which both Bob and bp contributed. The BP Excess
Compensation (Savings) Plan (ECSP) is a non-qualified, unfunded,
retirement savings plan to which bp notionally contributed 7% of base
salary above the annual IRS limit. In 2020 Bob made contributions to the
ESP totalling $28,500 and bp made matching contributions to the ESP,
and notional contributions to the ECSP, totalling $32,445. However,
investment losses in his unfunded ECSP account (aggregating the
unfunded arrangements relating to his overall service with bp and TNK-BP)
exceeded these contributions, hence the amount included in the single
figure table is zero.
bp Annual Report and Form 20-F 2020
113
History of chief executive officer remuneration
Year
Chief executive officer
Total
remuneration
thousanda
Annual
bonus % of
maximum
Performance
shares % of
maximum
Bob Dudley
2011
2012
Bob Dudley
2013 Bob Dudley
2014
Bob Dudley
Bob Dudley
2015
2016 Bob Dudley
2017
Bob Dudley
2018 Bob Dudley
2019 Bob Dudley
2020b Bob Dudley
Bernard Looney
$8,439
$9,609
$15,086
$16,390
$19,376
$11,904
$15,108
$15,253
$13,336
$188
£1,735
66.7
64.9
88.0
73.3
100.0
61.0
71.5
40.5
67.5
0
0
16.7
0
45.5
63.8
74.3
40.0
70.0
80.0
71.2
32.5
32.5
a Total remuneration figures include share vesting outcomes.
b 2020 figures show remuneration for the periods of qualifying service as CEO during 2020,
as per the single figure values on page 113.
Directors’ remuneration report continued
Brian Gilvary was provided with retirement benefits through a combination
of tax-qualified and non-qualified plans for service to 31 March 2011, but
linked to his final salary. In line with terms offered to UK employees
employed prior to 2010 (or before 2014 in the North Sea) Brian was a
member of the BP Pension Scheme (bpPS), a UK final salary defined benefit
pension plan. Pension benefits accrued in excess of the individual lifetime
tax allowance set by legislation were provided to Brian via a non-qualified,
unfunded pension arrangement designed to mirror the design of the
approved bpPS. His normal retirement age is 60, although due to his long
service, benefits accrued before 1 December 2006 may be paid unreduced
from age 55 with bp’s consent. Brian received no salary increase in 2020,
hence his interests in these retirement benefits did not increase and the
amount included in the single figure table is therefore zero.
For service after 31 March 2011 Brian received a cash allowance in lieu of
further accrual. This was set at 30% of salary to 30 May, then 25% of salary
to 30 June 2020, and the amount has been separately identified in the
single figure table.
Discontinued plans
In accordance with 2014 policy, Brian Gilvary compulsorily deferred one third
of his 2015 annual bonus and received a matching award of bp shares. Both
the deferred and matching awards were subject to a three-year
performance period which ended on 31 December 2018, however Brian
voluntarily requested that the committee delay the performance
assessment and vesting of the 2015 matching award for two years, to
31 December 2020.
The committee considered operational and financial performance and
reviewed safety and environmental sustainability performance over the
2016-20 period, seeking input from the strategy and sustainability
committee on safety and sustainability measures. The committee
concluded that safety performance continues to show improvement, with
safety embedded in the culture of the organization and supporting strong
operational and financial performance. The committee concluded that this
award should vest in full. Because this award vested post-employment, the
value is included in the payments to past directors statement on page 122,
with further details available in the deferred shares table on page 120.
Bob Dudley has previously requested that the committee delay the
performance assessment and vesting of all his deferred and matching
awards under the 2014 policy. Following the committee’s conclusion that
the original safety and environmental sustainability conditions have been
met, these awards will vest one year after his retirement, and the value will
be reported in the payments to past directors statement in our 2021 report.
114
bp Annual Report and Form 20-F 2020
Corporate governance
Over half of our global workforce participates in an annual cash bonus plan
and for 2020 the plan was intended to pay an incentive based equally on
individual performance and bp performance. However, as reported in my
opening letter, the committee and CEO both concluded that there should be
no bonus for 2020 as the plan was unaffordable, and this outcome applies
equally to our executive directors, leadership team, and those of our wider
workforce who participate in the annual bonus plan. These decisions reflect
our principle of consistency for all those rewarded under our common
template. Note, however, that a limited number of employees, such as
those with specific contractual rights or who work in parts of the business
with different remuneration models, have received bonus payments
for 2020.
Looking forward, we have reviewed the role of share plans offered to
employees with a view to understanding the extent to which these plans
align our wider workforce with bp’s purpose, particularly whether
employees are personally invested in the new ambition and able to share in
success. This review has led to our support for a ‘one off’ equity grant to
every bp employee in 2021, vesting in 2025, reflecting our belief in sharing
success broadly while aligning employees’ longer-term interests with all
shareholders.
We have also devoted time to examine the support provided for employee
health and wellbeing, to gain a better understanding of how these aspects
of policy support the organization’s culture and encourage appropriate
behaviours. This is an ongoing study and we will have more to report
next year.
Turning to non-discrimination matters, we understand the sharp interest that
exists in disclosures of gender and ethnicity pay gaps. Having reviewed the
gender pay gap reports of the last several years we are satisfied that reward
processes and decisions are designed and managed to effectively avoid
bias, and that reported pay gaps relate in the main to differences in gender
representation across the pay hierarchy. We therefore conclude that the
narrative accompanying our pay gap reporting is better reflected within bp’s
diversity and inclusion reporting, rather than remuneration reporting. With
this in mind, and because bp has committed to annual diversity and
inclusion reporting, we will leave additional commentary to that publication,
which is expected to be available on the company’s website bp.com
next month.
Wider workforce in 2020
Workforce experience
During 2020 the committee has continued to receive and review information
on pay outcomes and processes for our wider workforce in order to take
account of wider workforce pay and conditions when setting executive
remuneration, and to consider alignment between pay structures.
As part of this review we carried out a programme of engagement with a
diverse range of employees from different parts of the workforce from the
front line to corporate office and covering new joiners, employees with long
tenure in the organization, and employees of different gender and
nationality. The topics discussed addressed bp’s new purpose and ambition,
and how this aligns with the organization’s reward programmes. Our
enquiries ranged from success in attracting and retaining talent, employee
preferences in how pay is delivered, the make-up of the reward package,
and programmes to support international mobility. A recurring theme was
the desire for flexibility, with employees wanting to be empowered to make
their own choices about how they work and how they are remunerated for
their work.
Overall we continue to observe well-balanced and structured approaches to
reward. Although these approaches vary by business area and location, the
core offering for the majority of our workforce is summarized in the table on
page 116. We also find that financial reward is complemented with strong
emphasis on maintaining a supportive and inclusive working environment.
For instance, our commitment to family-friendly leave policies; recognition
as a top global employer in Stonewall’s list of the best multinational
employers for LGBT+ staff; and scoring 100% for a fourth consecutive year
in the Human Rights Campaign’s 2021 Corporate Equality Index, which
measures adoption of non-discrimination policies, equitable benefits for
LGBT+ employees and families, and supporting an inclusive culture and
corporate social responsibility. We are also pleased to confirm that bp is
now accredited by the Living Wage Foundation as a real living wage
employer in the UK. This ensures all colleagues in our UK businesses and at
company-owned sites are paid at least the real living wage and we are now
reviewing the position across other bp countries.
We apply the insights we gain from engaging with the workforce to
challenge leadership generally and to make sure we think about
remuneration holistically, not just with regard to those leaders whose pay is
within our remit. This has been more relevant than ever through a year in
which the COVID-19 pandemic has had such a significant impact on our
people and business. Wider workforce salary increases were postponed at
the normal salary review date 1 April 2020; from 1 October 2020 staff below
our senior leadership level did receive increases. Salaries remained frozen
for senior leaders (other than promotions) throughout 2020.
bp Annual Report and Form 20-F 2020
115
Directors’ remuneration report continued
Summary of remuneration structure for employees below the board
Element
Salary
Pensions and benefits
Annual bonus
Performance shares
Policy features for the wider workforce
Comparison with executive director remuneration
Our salary is the basis for a competitive total
reward package for all employees, and we conduct
an annual salary review for all non-unionized
employees.
As we determine salaries in this review, we take
account of comparable pay rates at other relevant
employers, the skills, knowledge and experience of
each individual, relativity to peers within bp,
individual performance, and the overall budget we
set for each country.
In setting the budget each year, we assess how
employee pay is currently positioned relative to
market rates, forecasts of any further market
increases, and business context related to such
things as growth plans, workforce turnover
and affordability.
We offer market-aligned benefits packages
reflecting normal practice in each country in which
we operate. Where appropriate, and subject to
scale, we offer significant elements of personal
benefit choice to our employees.
Over half of our global workforce participate in an
annual cash bonus plan that multiplies a target
bonus amount by a performance factor in the range
0 to 2.
For 2021, the performance factor will reflect bp
performance alone, placing emphasis on aligning
individual efforts to the shared goals of the company
at this critical stage of our transition.
We operate different bonus plans for those distinct
parts of our business where remuneration models in
the market are markedly different, such as our
trading and marketing businesses.
We operate a performance share plan with
three-year vesting for employees from our
professional entry level and above. Operation varies
based on seniority in three broad tiers: group
leaders (approximately 300); senior leaders
(approximately 4,000); and all other professional
employees (approximately 32,000 potential
participants, of whom 20% will participate). Vesting
is subject to group performance outcomes for the
group leader population only.
The salaries of our executive directors and executive
leadership form the basis of their total remuneration,
and we review these salaries annually.
The primary purpose of the review is to stay aligned
with relevant market comparators. We intend to
keep increases within the salary review budgets
set for our wider workforce, except in specific
circumstances.
Other than the addition of security-related benefits,
our executive director benefit packages are broadly
aligned with other employees who joined bp in the
same country at the same time.
Under our 2020 remuneration policy pension
benefits have been sharply reduced for our new
executive directors, who receive a cash-in-lieu of
pension allowance set at 15% of salary. Their
previously accrued defined benefit calculations are
capped on pre-appointment salary service.
Annual bonus for executive directors is directly
related to the same group performance measures
and outcomes as the wider workforce.
Performance shares for our executive directors
are assessed using the same group performance
scorecard used for the group leader
performance shares.
116
bp Annual Report and Form 20-F 2020
Corporate governance
Chief executive officer to employee pay ratio
This is our second year reporting the CEO pay ratio following the
requirements introduced in 2018. As last year, we have selected option A
as our reporting basis, being the most accurate approach available. The
employees included in these calculations were employed by the group on
31 December 2020 and pay and benefits values were determined with
reference to the financial year ending 31 December 2020. We confirm that
no broadly applicable components of pay have been omitted and, where
necessary, full-time equivalent pay has been calculated by simple
engrossment of part year values.
Our analysis this year covers more than 14,000 UK employees, 45% of
whom work in our retail sites. Employee values reflect the zero bonus
outcome for the majority of employees, and the delayed salary review date,
from 1 April to 1 October. Given the succession of CEO in 2020, these
employee values are compared against the sum of total pay values, per the
single figure table on page 113, for Bernard Looney and Bob Dudley.
Percentage change comparisons: Directors’
remuneration versus employees
In the table below, values in column ‘a’ represent the percentage change
in salary and fees; values in column ‘b’ represent the percentage change
in taxable benefits; and values in column ‘c’ represent the percentage
change in bonus outcomes for performance periods in respect of each
financial year.
The employee percentages shown represent the change in median
employee pay. This compares the median BP p.l.c. employee on
31 December of the relevant financial year, with the median BP p.l.c.
employee on 31 December of the preceding financial year, in each case
ranked based on the total of salary, benefits and bonus.
For the chair and non-executive directors, the decline in the value of taxable
benefits largely relates to the sharp drop in business travel arising from
pandemic-related travel restrictions.
Year
Method
2019 Option A
2020 Option A
25th
percentile:
pay ratio,
total
pay and
benefits,
(salary)
543:1
£19,108
(£18,845)
99:1
£18,984
(£18,984)
50th
percentile:
pay ratio,
total
pay and
benefits,
(salary)
75th
percentile:
pay ratio,
total
pay and
benefits,
(salary)
188:1
£55,071
(£38,800)
82:1
£126,085
(£74,200)
40:1
£46,933
(£29,040)
19:1
£98,546
(£80,475)
Bob Dudley’s pay has been converted from US dollars at 0.77907 for 2020. The 2019 ratio is as
originally reported.
The sharp reduction in 50th percentile ratio from 188:1 to 40:1 reflects the
fact that CEO remuneration is more heavily weighted to variable pay which
reduces in years of weaker performance such as 2020. This is a natural
reason for volatility in pay ratio reporting from year to year, and illustrates
one of the challenges in commenting on whether any given year’s pay ratio
is appropriate. Our considered view as to appropriateness is that the policies
for our CEO, and for the wider workforce, are both fit for purpose and that
they deliver pay outcomes appropriate to the circumstance of the year. Thus
differentials reflect both the relative contributions made at different levels in
our hierarchy, and the nature of the year in question.
Taken in the round with all of the insights we have gained into pay policies
and practices, we remain satisfied that pay outcomes, and the ratios derived
from them, are as they should be. In particular we note that as well as being
paid at least the real living wage, our UK employees also benefit from the
significant intangible value of working in an inclusive and caring enterprise
that is not reflected in pay ratio analyses.
Employees
Bernard Looney
Murray Auchincloss
Bob Dudley
Brian Gilvary
Nils Andersen
Dame Alison Carnwath
Pamela Daley
Sir Ian Davis
Professor Dame Ann Dowling
Helge Lund (Chair)
Melody Meyer
Tushar Morzaria
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
2020 v 2019
b
0%
–
–
-5%
13%
-46%
-94%
-92%
-81%
-96%
-74%
-77%
–
-71%
-92%
-83%
a
0%
–
–
0%
1%
-7%
-4%
-15%
-14%
-4%
0%
9%
–
-7%
2%
-3%
c
-100%
–
–
-100%
-100%
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Bob Dudley, Brian Gilvary and Nils Andersen resigned during 2020, therefore, other than for
one-time items, their 2020 pay has been annualised for comparison.
Bernard Looney, Murray Auchincloss and Tushar Morzaria were appointed on the board in 2020 and
therefore no comparison to 2019 is available.
Relative importance of spend on pay ($ million)
Distributions to
shareholders
Remuneration paid
to all employees
Capital
investment
9,844
9,872 9,878
6,340
15,238
12,034
2019
2020
2019
2020
2019
2020
bp Annual Report and Form 20-F 2020
117
Directors’ remuneration report continued
Stewardship and executive director interests
We believe that our executive directors should have a material interest in the company, both during their tenure and after they leave bp. Our 2020
remuneration policy therefore requires the CEO and other executive directors to build personal shareholdings of five times salary and four and half times
salary, respectively, within five years of their appointment. They are expected to maintain those shareholding levels for two years post employment.
Directors’ shareholdings (audited)
The table below details the personal shareholdings of each current and former executive director. Both Bob Dudley and Brian Gilvary significantly exceed
their post-employment shareholding commitment. Bernard Looney and Murray Auchincloss are building towards the policy requirement that applies five
years from their dates of appointment, 5 February and 1 July 2020 respectively. These figures include all beneficial and non-beneficial ownership of shares
of bp (or calculated equivalents) that have been disclosed to the company.
Director
Bernard Looney
Murray Auchincloss
Bob Dudleyb
Brian Gilvaryb
Ordinary
shares or
equivalents
at 1 Jan
2020
–
–
4,592,208
2,593,708
Ordinary
shares or
equivalents
at 31 Dec
2020
Changes
from 31 Dec
2020 to
2 Mar 2021
Ordinary
shares or
equivalents
at 2 Mar
2021
Appointment date
Value of
current
shareholding
Multiple
of salary
achieved
331,711
139,525
–
–
212,228
2,010
–
–
543,939 5 February 2020 £1,615,499a
£420,359a
1 July 2020
141,535
–
October 2010
–
–
January 2012
–
1.24x
0.60x
–
–
a Based on ordinary share price at 2 March 2021 of £2.97.
b Bob Dudley and Brian Gilvary resigned on 4 February and 30 June 2020 respectively.
These current and former executive directors have additional interests in restricted and performance shares, and Bob and Brian have various interests in
deferred bonus shares. These additional share interests are shown in aggregate, and by plan, in the tables below. For performance shares, the figures
reflect maximum possible vesting levels (excluding the addition of reinvested dividends) even though the actual number of shares that vest will depend on
the extent to which performance conditions are satisfied.
Aggregated interests, all plans (audited)
Directora
Bernard Looney
Murray Auchincloss
Bob Dudley
Brian Gilvary
Unvested
ordinary
shares or
equivalents
at 1 Jan
2020
–
–
6,639,882
2,905,764
Unvested
ordinary
shares or
equivalents
at 31 Dec
2020
3,193,599
1,581,899
5,296,740
2,060,135
Changes
from 31 Dec
2020 to
2 Mar 2021
-530,370
-2,755
–
–
Unvested
ordinary
shares or
equivalents
at 2 Mar
2021
2,663,229
1,579,144
–
–
a Bernard Looney was appointed as CEO on 5 February and Murray Auchincloss was appointed as CFO on 1 July 2020, Bob Dudley and Brian Gilvary resigned on 4 February and 30 June 2020 respectively.
118
bp Annual Report and Form 20-F 2020
Corporate governance
Performance shares (audited)
Share element interests
Interests vested in 2020 and 2021
Performance
period
Date of award of
performance shares
At 1 Jan
2020
Awarded
2020
At 31 Dec
2020
Potential maximum performance sharesa
Bernard Looney
Murray Auchincloss
Bob Dudleye
Brian Gilvary
2018-20b
2019-21b
2020-22d
2018-20be
2019-21be
2020-22d
2017-19f
2018-20g
2019-21
2017-19f
2018-20g
2019-21
20 Mar 2018
25 Mar 2019
11 Aug 2020
20 Mar 2018
25 Mar 2019
11 Aug 2020
19 May 2017
22 May 2018
19 Feb 2019
19 May 2017
22 May 2018
19 Feb 2019
317,380
335,920
–
155,916
156,468
–
1,571,628
1,395,600
1,340,766
722,093
696,705
654,315
Number
of ordinary
shares
vested
126,134
–
–
62,124
–
–
–
–
2,076,677
317,380
335,920
2,076,677
–
–
999,201
155,916
156,468
999,201
–
–
–
–
–
–
–
1,395,600
1,340,766
1,358,334
410,922
–
–
696,705
654,315
623,242
227,337
–
Vesting date
16 Feb 2021
–
–
10 Mar 2021
–
–
18 Feb 2020
19 Feb 2021
–
18 Feb 2020
19 Feb 2021
–
Face value
of awardc, £
1,840,842
6,396,165
857,445
3,077,539
–
–
7,199,913
–
–
3,513,672
a For awards under the 2017-19 plan, performance conditions are measured 50% on TSR relative to Chevron, ExxonMobil, Shell and Total (‘comparator companies’) over three years, 30% on ROACE based
on performance in 2019, and 20% on strategic progress assessed over the performance period.
For awards under the 2018-2020 plans, performance conditions are measured on the same basis as the 2017-2019 plan, except ROACE which will be based on performance in the last two years of the
performance period (i.e. 2019 and 2020).
For awards under the 2019-2021 plans, performance conditions are measured 50% on TSR relative to the comparator companies over three years, 20% ROACE averaged over the full performance
period, and 30% on strategic progress assessed over the performance period.
Each performance period ends on 31 December of the third year.
b Awards granted under the Group Share Value Plan (GSVP) prior to appointment as executive directors (disclosed share interests reflect maximum vesting, though under this plan awards are granted at
50% of maximum). Represents vesting of shares at the end of the performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested.
Bernard Looney’s 2018-20 award vested on 16 February 2021, when the market price was £2.78 for each share, and Murray Auchincloss’s award vested on 10 March 2021 when the market price for
each ADS was $26.65. The amounts reported as 2020 income on the single figure table are therefore £351k for Bernard Looney and $275k (£215k) for Murray Auchincloss.
c Face values have been calculated using market prices of ordinary shares at closing on the dates of award, as follows; £5.37 on 19 February 2019; £5.48 on 25 March 2019; and £3.08 on 11 August 2020.
d Minimum vesting under these awards (below threshold performance) is 0%. At the lowest performance outcome that would yield an above-zero score on each measure, vesting would be 10% of
maximum.
e These awards were received in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares.
f Represents vesting of shares at the end of the performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested. This 2017-2019 award
vested on 18 February 2020, when the market price was £4.54 for each ordinary share, and $36.09 for each ADS. Reinvested dividends were delivered on 5 November 2020, when the market price was
£2.03 for each ordinary share, and $15.83 for each ADS. The adjusted amounts reported as 2019 income on the single figure table are therefore $8.039 million for Bob Dudley, and £2.787 million for Brian
Gilvary.
g Represents vestings of shares at the end of the performance period based on performance achieved under rules of the plan, pro-rated for time served, and includes reinvested dividends on the shares
vested. This 2018-2020 award vested on 19 February 2021, when the market price was £2.72 for each share, and $22.87 for each ADS. As they were received post-employment, the value of these
vested shares are included in the payments to past directors section on page 122.
Restricted shares (audited)
Bernard Looney
Murray Auchincloss
Share element interests
Number of restricted shares
Restricted
period
Date of award of
restricted shares
At 1 Jan
2020
Awarded
2020
At 31 Dec
2020
Face value
of awardc, £
2016-20a
2018-20a
2018-20b
2019-21b
2018-20a
2018-22a
2018-20b
2018-20d
2019-21d
2019-21b
2020-22d
15 Mar 2016
20 Mar 2018
20 Mar 2018
25 Mar 2019
20 Mar 2018
20 Mar 2018
20 Mar 2018
20 Mar 2018
25 Mar 2019
25 Mar 2019
28 Aug 2020
75,000
104,577
137,990
146,055
43,170
43,170
86,616
2,755
2,835
86,928
–
–
–
–
–
–
–
–
–
–
–
4,840
75,000
104,577
137,990
146,055
43,170
43,170
86,616
2,755
2,835
86,928
4,840
256,500
485,237
640,274
800,381
200,308
200,308
401,898
12,783
15,536
476,365
12,778
a Awards made under the Restricted Share Plan II prior to appointment as a director.
b Awards made under the Individual Share Value Plan prior to appointment as a director. Awards under this plan were granted at 100% of salary.
c Face values have been calculated using market prices of ordinary shares at closing on the dates of award, as follows; £3.42 on 15 March 2016; £4.64 on 20 March 2018; £5.48 on 25 March 2019; £2.64
on 28 August 2020.
d Interests of person closely associated with Murray Auchincloss.
bp Annual Report and Form 20-F 2020
119
Directors’ remuneration report continued
Deferred sharesa (audited)
Bonus year
Bob Dudleybc
2014
Brian Gilvary
2015
2016
2017
2018
2019
2014
2015
2016
2017
2018
2019
Deferred share element interests
Potential maximum deferred shares
Interests vested in 2020 and 2021
Type
Comp
Vol
Mat
Comp
Vol
Mat
Comp
Mat
Comp
Comp
Comp
Mat
Mat
Comp
Matg
Comp
Comp
Comp
Performance
period
Date of award of
deferred shares
At 1 Jan
2020
Awarded
2020
At 31 Dec
2020
2015-17
2015-17
2015-17
2016-18
2016-18
2016-18
2017-19
2017-19
2018-20
2019-21
2020-22
2015-17
2016-18
2017-19
2017-19
2018-20
2019-21
2020-22
11 Feb 2015
11 Feb 2015
11 Feb 2015
4 Mar 2016
4 Mar 2016
4 Mar 2016
19 May 2017
19 May 2017
22 May 2018
19 Feb 2019
18 Feb 2020
11 Feb 2015
4 Mar 2016
19 May 2017
19 May 2017
22 May 2018
19 Feb 2019
18 Feb 2020
147,054
147,054
294,108
275,892
275,892
551,784
147,642
147,642
226,236
118,584
–
176,576
318,042
73,070
73,070
127,457
64,436
–
–
–
–
–
–
–
–
–
–
–
228,486
–
–
–
–
–
–
126,110
147,054
147,054
294,108
275,892
275,892
551,784
147,642
147,642
226,236
118,584
228,486
–
318,042
–
73,070
127,457
64,436
126,110
Number
of ordinary
shares
vested Vesting date
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
253,223e 18 Feb 20
402,227f 19 Feb 21
88,577e 18 Feb 20
–
153,562h 19 Feb 21
–
–
–
–
–
Face value
of the
awardd, £
655,861
655,861
1,311,722
1,015,283
1,015,283
2,030,565
696,870
696,870
1,330,268
636,796
1,046,466
–
–
–
344,890
–
346,021
577,584
a Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle. If the committee assesses that there has been a material deterioration in safety and
environmental performance, or there have been major incidents, either of which reveal underlying weaknesses in safety and environmental management, then it may conclude that shares should vest
only in part, or not at all. In reaching its conclusion, the committee obtains advice from the SAS committee. There is no identified minimum vesting threshold level. ‘Comp’ denotes compulsory deferral,
‘Vol’ denotes voluntary deferral, and ‘Mat’ denotes matching awards.
b Bob Dudley received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares.
c Bob Dudley has voluntarily agreed to defer vesting of these awards until one year post employment.
d Face values have been calculated using market prices of ordinary shares on the dates of award, as follows; £4.46 on 11 February 2015; £3.68 on 4 March 2016; £4.72 on 19 May 2017; £5.88 on 22 May
2018; £5.37 on 19 February 2019; £4.58 on 18 February 2020.
e Represents vestings of shares at the end of the deferral period and includes reinvested dividends on the shares vested. The market price of each share used to determine the total value at vesting on
18 February 2020 was £4.54. The additional reinvested dividend shares were delivered on 5 November 2020, at a market price of £2.03. The adjusted amount reported as 2019 income on the single
figure table is therefore £1.529 million.
f Represents vesting of shares made at the end of the deferral period, prorated for 54 months’ service out of 60 months’ vesting period, and includes reinvested dividends thereon. The market price of
each share used to determine the total value at vesting on 19 February 2021 was £2.72. As they were received post-employment, the values of these vested shares are included in the payments to past
directors section on page 122.
g Brian Gilvary has voluntarily agreed to defer vesting of this 2016 matching award to at least one year post employment.
h In line with the 2017 policy, these compulsory deferrals of Bob and Brian’s 2017 bonus were included in the single figure of total remuneration reported for 2017 and therefore the values of these shares
are not included as payments to past directors.
In common with many of our UK employees, Bernard Looney holds options under the bp group save as you earn (SAYE) scheme as shown below.
These options are not subject to performance conditions.
Share interests in share option plans (audited)
Director
Option type
Bernard Looney
Murray Auchincloss
Brian Gilvary
Brian Gilvary
SAYE
SAYEb
BP 2011c
SAYEd
At 1 Jan
2020
6,024
–
400,000
2,064
Granted
Exercised
2020a Option price
At 31 Dec
Market
price at date
of exercise
–
3,614
–
–
–
–
–
–
6,024
3,614
400,000
–
£2.54
£2.54
£3.72
£4.36
–
–
–
–
Date from which
first exercisable
01 Sep 2025
01 Sep 2023
07 Sep 2014
01 Sep 2022
Expiry date
28 Feb 2026
28 Feb 2024
07 Sep 2021
28 Feb 2023
a The closing market price of an ordinary share on 31 December 2020 was £2.55. During 2020 the highest market price was £5.04, and the lowest market price was £1.93.
b Interest of person closely associated with Murray Auchincloss.
c The BP 2011 plan – these options were granted to Brian Gilvary prior to his appointment as a director and are not subject to performance conditions.
d Brian Gilvary closed his save as you earn contract, and therefore these options lapsed, on 18 June 2020.
Bernard Looney, Murray Auchincloss, Bob Dudley and Brian Gilvary have no interests in bp preference shares, debentures or option plans (other than as
listed above), and none have interests in shares or loan stock of any subsidiary company.
No directors or other leadership team members own more than 1% of the ordinary shares in issue. At 2 March 2021, our directors and leadership team
members collectively held interests of 5,294,828 ordinary shares or their calculated equivalents, 10,204,082 restricted share units (with or without
conditions) or their calculated equivalents, 3,075,878 performance shares or their calculated equivalents and 1,580,380 options over ordinary shares
or their calculated equivalents, under bp group share option schemes.
120
bp Annual Report and Form 20-F 2020
Corporate governance
Post employment share ownership interests
Bob Dudley and Brian Gilvary have, and will continue to retain, significant interests in bp post employment. Under our 2017 policy, they gave their personal
commitment as executive directors to maintain actual holdings equivalent to two and a half times salary for two years post employment. Their ongoing
interests in share awards under group plans which remain subject to vesting and/or holding periods materially exceed the two and a half times salary
threshold, and thus guarantee that they will continue to meet their minimum shareholding commitment. Although we instituted a formal post employment
share ownership requirement as part of our 2020 policy, given the foregoing, we have not modified the requirements for these former executives.
Chair and non-executive director outcomes and interests
The remuneration policy for the chair and non-executive directors (NEDs) was approved at the 2020 AGM and implemented during 2020.
Fee structure
The table below shows the fee structure for the chair and NEDs, per our 2020 policy. The chair is not eligible for committee chairmanship and membership
fees or intercontinental travel allowance.
Chair
Senior independent directora
Board member
Audit, geopolitical, remuneration and SAS committees chairmanship feesb
Committee membership feec
Intercontinental travel allowance
Fees
£ thousand
785
120
90
30
20
5
a The senior independent director is eligible for committee chairmanship fees and intercontinental travel allowance plus any committee membership fees.
b Committee chairs do not receive an additional membership fee for the committee they chair.
c For members of the audit, geopolitical, SAS and remuneration committees.
As disclosed in our 2019 report, in early 2020 a revised fee structure was adopted for implementation with effect from 1 June 2020. The implementation of
that revised fee structure was postponed on account of the COVID-19 pandemic and actions taken by bp in response.
With effect from 1 January 2021, a fee for membership of the people and governance committee has been introduced given the increased time
commitment associated with the expanded responsibilities of this committee. The fee is in line with other committee membership fees. The senior
independent director has waived her entitlement to this committee membership fee.
The geopolitical advisory council was constituted with effect from 1 January 2021. Fees of £10,000 and £15,000 are payable for membership of and
chairing the council, respectively.
The fee structure for 2021 remains otherwise unchanged and the board will review the situation again during the year.
The table below shows the fees paid and applicable benefits for the year ended 31 December 2020. Benefits include travel and other expenses relating to
the attendance at board and other meetings. As chair throughout 2020, Helge Lund had the use of a fully maintained office for company business, a car and
driver, and security advice in London. Benefits values have been grossed up using a tax rate of 45%, where relevant, as an estimation of tax due.
2020 remuneration (audited)
£ thousand
Nils Andersenb
Dame Alison Carnwathb
Pamela Daley
Sir Ian Davisb
Professor Dame Ann Dowlingc
Helge Lund (Chair)
Melody Meyer
Tushar Morzariab
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Fees
Benefits
Totala
2020
2019
2020
2019
2020
2019
38
110
140
143
135
785
166
37
140
174
140
161
115
164
165
140
785
152
–
150
170
145
1
2
3
1
0
25
4
0
3
3
0
11
33
37
5
3
95
16
–
11
36
1
39
112
143
143
135
810
170
37
143
177
140
172
148
201
170
143
880
168
–
161
206
146
a Due to rounding, the totals may not agree exactly with the sum of the component parts.
b Nils Andersen resigned on 18 March 2020. Sir Ian Davis resigned on 30 December 2020. Tushar Morzaria was appointed on 1 September 2020. Dame Alison Carnwath resigned on 14 January 2021.
c Fee includes £25,000 for chairing and being a member of the bp technology advisory council.
bp Annual Report and Form 20-F 2020
121
Directors’ remuneration report continued
Chair and non-executive directors’ interests (audited)
The figures below include all the beneficial and non-beneficial interests of the chair and each non-executive director of the company in shares of bp (or
calculated equivalents) that have been disclosed according to the disclosure guidance and transparency rules in the Financial Conduct Authority handbook
(‘the DTRs’) as at the applicable dates. Our policy, shown on page 126, includes a shareholding guideline encouraging non-executive directors to establish a
holding in bp shares of the equivalent value of one year’s base fee.
Nils Andersenb
Dame Alison Carnwathb
Pamela Daley
Sir Ian Davisb
Professor Dame Ann Dowling
Helge Lund (Chair)
Melody Meyer
Tushar Morzariab
Brendan Nelsond
Paula Rosput Reynolds
Karen Richardsonb
Sir John Sawers
Dr Johannes Teyssenb
Ordinary
shares or
equivalents
at 1 Jan
2020
Ordinary
shares or
equivalents
at 31 Dec
2020
Changes
from 31 Dec
2020 to
2 Mar 2021
Ordinary
shares or
equivalents
at 2 Mar
2021
Value of
current
shareholdinga
% of policy
achieved
125,000
17,700
17,592c
52,671
22,320
600,000
20,646c
–
21,626
73,200c
–
15,506
–
–
17,700
40,332c
–
22,320
600,000
20,646c
36,276
21,626
73,200c
–
23,116
–
–
–
0
–
0
0
0
0
0
0
–
0
–
–
–
40,332c
–
22,320
600,000
20,646c
36,276
21,626
73,200c
10,746c
23,116
20,000
–
–
$166,504
–
£66,290
£1,782,000
$85,234
£107,740
£64,229
$302,194
$44,363
£68,655
£59,400
–
–
144%
–
74%
227%
74%
120%
71%
262%
38%
76%
66%
a Based on share and ADS prices at 2 March 2021 of £2.97 and $24.77.
b Nils Andersen and Sir Ian Davis resigned on 18 March and 30 December 2020 respectively. Tushar Morzaria appointed on 1 September 2020. Karen Richardson and Dr Johannes Teyssen appointed on
1 January 2021. Dame Alison Carnwath resigned on 14 January 2021.
c Held as ADSs.
d Brendan Nelson’s 31 December 2019 shareholding was incorrectly shown as 11,040 shares, rather than 21,626 shares, in our 2019 report.
Payments for loss of office (audited)
Brian Gilvary received a payment in lieu of notice of £447,950 relating to the part of his 12-month notice period that followed his retirement on
30 June 2020.
As detailed on page 120, Bob Dudley deferred the vesting of various deferred and matching share awards, related to annual bonus outcomes from 2014 to
2019, until at least one year post retirement. Of these, awards under the 2014 policy (for bonus years 2014, 2015 and 2016) were not included in the single
figures of total remuneration, therefore the values of these awards will be disclosed in the payments to past directors section of the relevant annual report
following vesting.
Similarly, Brian Gilvary deferred the vesting of his 2016 matching share award until at least one year post retirement. The value of this award will be
disclosed in the payments to past directors section of the relevant annual report following vesting.
Payments to past directors (audited)
Since leaving employment, Bob Dudley and Brian Gilvary have received shares upon vesting of the awards listed below:
(1) Bob Dudley received 410,922 shares on vesting of his 2018-20 performance share award on 19 February 2021. Based on a share price of $22.78 this
vesting was valued at $1,566,298. This award reflects the 32.5% vesting outcome, and has been pro-rated for 27 months’ service through the three-year
performance period.
(2) Brian Gilvary received 227,337 shares on vesting of his 2018-20 performance share award on 19 February 2021. Based on a share price of £2.72 this
vesting was valued at £618,357. This award reflects the 32.5% vesting outcome, and has been pro-rated for 30 months’ service through the three-year
performance period.
(3) Brian Gilvary received 402,227 shares on vesting of his 2015 matching award on 19 February 2021. Based on a share price of £2.72 this vesting was
valued at £1,094,057. This award has been pro-rated for 54 months’ service through the five-year vesting period.
Bob Dudley was also provided with post-employment medical benefits amounting to $14,359, ongoing car and driver benefits in the UK, amounting to
$44,429, and relocation benefits to assist his repatriation to the US, amounting to $47,186.
We made no other payments within the scope of the disclosure requirements to any past director of bp during 2020 (we have no de minimis threshold
for such disclosures).
122
bp Annual Report and Form 20-F 2020
Other disclosures
Historical TSR performance
£250
£200
£150
£100
£50
£0
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
BP
FTSE 100
This graph shows the growth in value of hypothetical £100 investments in
BP p.l.c. ordinary shares, and in the FTSE 100 Index (of which bp is a
constituent), over 10 years from 31 December 2010 to 31 December 2020.
Independence and advice
The board considers all committee members to be independent with no
personal financial interest, other than as shareholders, in the committee’s
decisions. Further detail on the activities of the committee, advice received,
and shareholder engagement is set out in the remuneration committee
report on page 105.
During 2020 Ben Mathews, who was employed by the company
and reported to the chair of the board, acted as secretary to the
remuneration committee.
The committee also received advice on various matters relating to the
remuneration of executive directors and senior management from Helmut
Schuster, former EVP, group human resources, Kerry Dryburgh, EVP, people
and culture (from 1 July 2020) and Ashok Pillai, SVP, reward and wellbeing.
PricewaterhouseCoopers LLP (‘PwC’) continued to provide independent
advice to the committee in 2020, following its appointment as independent
advisor to the committee in September 2017, following a competitive tender
process. None of PwC’s consultants advising the committee have any
connection with the company’s directors. PwC advice included, for
example, support with remuneration benchmarking and updates on market
practice. PwC is a member of the Remuneration Consulting Group and,
as such, operates under the code of conduct in relation to executive
remuneration consulting in the UK. The committee is satisfied that the
advice received is objective and independent.
Freshfields Bruckhaus Deringer LLP (‘Freshfields’) provided legal advice
on specific compliance matters to the committee.
PwC and Freshfields provide other advice in their respective areas to
the group. During the year, PwC provided bp with services including:
subsidiary company secretarial support; digital and IT services; low
carbon strategy consulting; internal audit subject matter expertise and
trading transformation.
Total fees or other charges (based on an hourly rate) for the provision of
remuneration advice to the committee in 2020 (save in respect of legal
advice) were £110,262 to PwC.
Corporate governance
Considerations related to the Corporate Governance Code
When setting the 2020 policy, the committee concluded that the scorecard-
based approach to setting targets and measuring outcomes provides great
clarity in our ability to engage transparently with shareholders and the wider
workforce on remuneration. Thus, bp continues to operate a simple
structure of market-aligned salary with annual and three-year performance-
based incentives. Risks are managed through careful setting of performance
measures and targets, and broad options to apply committee discretion in
assessing outcomes, such as the decision to pay no annual bonus for 2020.
These are complemented with robust malus and clawback measures.
Remuneration outcomes are predictable, as shown in the scenario charts of
the 2020 policy, and proportional by virtue of the challenging performance
levels required to achieve target pay outcomes. Through material weighting
in measures related to safety, sustainability and strategy, as shown on page
109, remuneration aligns closely with bp’s culture, as expressed through our
purpose and ambition.
Shareholder engagement
Throughout 2020 we continued to discuss remuneration policy and
approach with many of our largest shareholders, as well as investor
representative bodies. We plan to continue this dialogue in 2021, as we
consider issues and make decisions related to the implementation of our
remuneration policy for 2021 and beyond.
The table below shows the votes on the report for the last three years.
AGM directors’ remuneration report vote results
Year
2020
2019
2018
% vote
‘for’
% vote
‘against’
Votes
withheld
96.05%
95.93%
96.42%
3.95%
67,623,825
4.07% 337,586,814
42,741,541
3.58%
The remuneration policy was approved by shareholders at the 2020 AGM
last May. The votes on the policy are shown below.
2020 AGM directors’ remuneration policy vote results
Year
2020
% vote
‘for’
% vote
‘against’
Votes
withheld
96.58%
3.42%
65,652,222
External appointments
The board supports executive directors taking up appointments outside
the company to broaden their knowledge and experience. Each executive
director is permitted to retain any fee from their external appointments.
Such external appointments are subject to agreement by the chair and
reported to the board. Any external appointment must not conflict with
a director’s duties and commitments to bp. Details of appointments as
non-executive directors of publicly listed companies during 2020 are
shown below.
Director
Appointee
company
Additional position
held at appointee
company
Bernard Looney
Murray Auchincloss
Bob Dudley
Brian Gilvary
Rosnefta
Aker BP ASAa
Rosnefta
Air Liquide SA
Brian Gilvary
Barclays plc
Director
Director
Director
Non-executive
director
Non-executive
director
Total fees
0
0
0
Eur 38,375
£47,500
a Held as a result of the company’s shareholdings in Rosneft and Aker BP ASA.
bp Annual Report and Form 20-F 2020
123
Directors’ remuneration report continued
Policy implementation for 2021
The table below shows how the remuneration policy approved by shareholders at the 2020 AGM will be implemented in 2021, alongside a summary
of key features.
For the full remuneration policy, please go to bp.com/remuneration
Salary and benefits
Retirement benefits
Annual bonus
Performance shares
To provide fixed remuneration to reflect the scale
and complexity of both the business and the role,
and to be competitive with the external market.
When setting salaries, the committee considers
practice in other oil and gas majors as well as
European and US companies of a similar size,
geographic spread and business dynamic to bp.
Percentage increases for executive directors will not
exceed increases for the broader employee
population, other than in specific circumstances
identified by the committee (e.g. in response to a
substantial change in responsibilities).
Executive directors normally participate in the
company retirement plans that operate in their
home country.
New appointees from within the bp group retain
previously accrued benefits. For their service as a
director, retirement benefits will be no more than
the median provision offered to the wider workforce
in the UK.
For future appointments, the committee will
carefully review any retirement benefits to be
granted to a new director, taking account of
retirement policies across the wider group and any
arrangements currently in place.
Bonus is measured against an annual scorecard. The
committee holds discretion to choose the specific
measures and the relative weightings adopted in the
annual scorecard, to reflect the annual plan as
agreed with the board.
Numeric scales are set for each measure, to score
outcomes relative to targets. A scorecard outcome
of 1.0 reflects the target outcome, and half of the
maximum outcome.
Target bonus is 112.5% of salary, and maximum
bonus is 225% of salary.
Half of the bonus for each year is paid in cash, and
half is delivered as a deferred share award vesting in
three years.
Performance shares are granted with a three-year
performance period, measured against scorecard.
The committee holds discretion to choose the
specific measures and the relative weightings
adopted in the scorecard, to ensure they are
focused on the near-term priorities for delivering the
bp strategy in the interests of shareholders.
Annual grants are 500% of salary for the CEO, and
450% of salary for any other executive director.
Awards will vest in proportion to the outcomes
measured through the performance scorecard,
subject to any adjustment by the committee.
Bernard Looney’s salary will increase by 2.75%
to £1,335,750 following the 2021 AGM.
Murray Auchincloss’s salary will increase by 8%
to £750,500 following the 2021 AGM.
This compares to an increase in excess of 4%
to our UK salaried staff effective from 1 April,
our annual salary review date.
Benefits will remain unchanged for 2021 and
include car-related provisions (or cash in lieu),
security assistance, insurance and medical cover.
Bernard and Murray are deferred members of
final salary pension plans related to their service
prior to appointment as executive directors, but
now receive a cash allowance in lieu of retirement
benefits.
Bernard’s cash allowance will be unchanged at
15%, and he accrues no further value under his
deferred pension.
Murray’s cash allowance will be unchanged at
15%, and he accrues no further value under his
US deferred pension.
For our 2021 bonus, our scorecard will be
reweighted to safety (15%), environment (15%),
operational (20%) and financial (50%).
Please see scorecard measures on page 125
for detail.
Awards are subject to malus and clawback
provisions described on page 125.
For our 2021-23 cycle, 20% each for rTSR,
ROACE, and EBIDA CAGR, and 40% for strategic
progress.
Please see scorecard measures on page 125 for
detail.
The 2021-23 awards will be granted in June 2021,
based on the average closing share price over the
90 days preceding our 2021 AGM.
Awards are subject to malus and clawback
provisions described on page 125.
124
bp Annual Report and Form 20-F 2020
Corporate governance
Bernard and Murray have not yet reached five
years since appointment, and are therefore
building the share interests towards the level
required by policy.
The committee has committed to an ongoing
review of the outcomes of 2020-22 performance
shares to ensure there is no windfall gain related
to share price appreciation following market
turmoil around the time the awards were granted.
Shareholding requirement
Malus and clawback
Committee flexibility
CEO to build a shareholding of at least five times
salary, and other executive directors four and a half
times salary, within five years of appointment.
Executive directors are required to maintain at
least that minimum level for at least two years
post employment.
Malus provisions may apply where there is: a
material safety or environmental failure; an incorrect
award outcome due to miscalculation or incorrect
information; a restatement due to financial reporting
failure or misstatement of audited results; material
misconduct; or other exceptional circumstances that
the committee considers similar in nature.
Clawback provisions may apply where there is: an
incorrect outcome due to miscalculation or incorrect
information; a restatement due to financial reporting
failure or misstatement of audited results; or
material misconduct.
The committee holds discretion to adjust
performance measures and weightings, and to
revise the peer group for the rTSR measure.
This discretion allows appropriate re-alignment,
throughout the policy term, for changes in the
annual plan and for the anticipated evolution of
the low carbon business environment.
The committee also holds discretion in
determining the outcomes for annual bonus
and performance shares, allowing them to take
broad views on alignment with shareholder
experience, environmental, societal and other
relevant considerations.
Performance measures for incentive plans commencing in 2021
Annual bonus (weighting as % of maximum)
Safety
15%
Tier 1/2 process safety
Environment
15%
Sustainable emissions
reductions
Operational performance
20%
bp-operated plant reliability
and refining availability (10%)
Margin share from convenience
and electrification (10%)
Financial performance
50%
Free cash flow (25%)
Cumulative cash cost reductions
(25%)
Performance shares (weighting as % of maximum)
Relative TSR
20%
ROACE
20%
Growth (EBIDA CAGR)
20%
Underpin: To take into account safety outcomes prior to determining final vesting percentage
Discretion: To reflect shareholder experience, environment, societal and other inputs
Robust malus and clawback
Strategic progress
40%
Deliver value through a resilient
and focused hydrocarbon business
Demonstrate a track record, scale
and value in low carbon electricity
and energy
Accelerate growth in convenience
and mobility
bp Annual Report and Form 20-F 2020
125
Directors’ remuneration report continued
Policy table – non-executive directors
Non-executive chair
Fees
Approach
Remuneration is in the form of cash fees, payable monthly. The level and structure of the chair’s remuneration
will primarily be compared against UK best practice.
Operation and opportunity
The quantum and structure of the non-executive chair’s remuneration is reviewed annually by the remuneration
committee, which makes a recommendation to the board.
Benefits and expenses
Approach
The chair is provided with support and reasonable travelling expenses.
Operation and opportunity
The chair is provided with an office and full-time secretarial and administrative support in London and a
contribution to an office and secretarial support in his home country as appropriate. A car and the use of a
driver is provided in London, together with security assistance. All reasonable travelling and other expenses
(including any relevant tax) incurred in carrying out his duties are reimbursed.
Non-executive directors
Fees
Approach
Operation and opportunity
Intercontinental allowance
Approach
Remuneration is in the form of cash fees, payable monthly. Remuneration practice is consistent with
recognized best practice standards for non-executive directors’ remuneration and, as a UK-listed company,
the level and structure of non-executive directors’ remuneration will primarily be compared against UK
best practice.
Additional fees may be payable to reflect additional board responsibilities, for example, committee
chairmanship and membership and for the role of senior independent director.
The level and structure of non-executive directors’ remuneration is reviewed by the chair, the CEO and the
company secretary who make a recommendation to the board. Non-executive directors do not vote on their
own remuneration.
Remuneration for non-executive directors is reviewed annually.
Non-executive directors receive an allowance to reflect the global nature of the company’s business. The
intercontinental travel allowance is payable for the purpose of attending board or committee meetings or
site visits.
Operation and opportunity
The allowance is paid in cash following each event of intercontinental travel.
Benefits and expenses
Approach
Operation and opportunity
Shareholding guidelines
Approach
Non-executive directors are provided with administrative support and reasonable travelling expenses.
Professional fees are reimbursed in the form of cash, payable following the provision of advice and assistance.
Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including
any relevant tax) incurred in carrying out their duties. The reimbursement of professional fees incurred
by non-executive directors based outside the UK in connection with advice and assistance on UK tax
compliance matters.
Non-executive directors are encouraged to establish a holding in bp shares of the equivalent value of one year’s
base fee.
This directors’ remuneration report was approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary, on 22 March 2021.
126
bp Annual Report and Form 20-F 2020
Corporate governance
UK Corporate Governance
Code compliance
Throughout 2020, bp applied the principles and
complied with all the provisions of the 2018 UK
Corporate Governance Code.
Risk management and internal control
Under the UK Corporate Governance Code 2018
(Code), the board is responsible for the
company’s risk management and internal control
systems. In discharging this responsibility the
board, through its governance principles, requires
the chief executive officer to operate the
company with a comprehensive system of
controls and internal audit to identify and manage
the risks including emerging risks that are
material to bp. In turn, the board, through its
monitoring processes, satisfies itself that these
material risks are identified and understood by
management and that systems of risk
management and internal control are in place to
mitigate them. These systems are reviewed
periodically by the board, have been in place for
the year under review and up to the date of this
report and are consistent with the requirements
of Principle O of the Code.
The board has processes in place to:
Assess the principal and emerging risks facing
the company.
Monitor the company’s system of internal
control (which includes the ongoing process
for identifying, evaluating and managing the
principal and emerging risks).
Review the effectiveness of that system annually.
Directors’ statements
Statement of directors’ responsibilities
The directors are responsible for preparing the
annual report and the financial statements in
accordance with applicable law and regulations.
The directors are required by the UK Companies
Act 2006 to prepare financial statements for each
financial year that give a true and fair view of the
financial position of the group and the parent
company and the financial performance and cash
flows of the group and parent company for that
period. Under that law they are required to
prepare the consolidated financial statements in
accordance with International Financial Reporting
Standards (IFRS) adopted pursuant to Regulation
(EC) No 1606/2002 as it applies in the European
Union (EU) and applicable law and have elected to
prepare the parent company financial statements
in accordance with applicable United Kingdom
law and United Kingdom accounting standards
(United Kingdom generally accepted accounting
practice), including FRS 101 ‘Reduced Disclosure
Framework’. In preparing the consolidated
financial statements the directors have also
elected to comply with IFRS as issued by the
International Accounting Standards Board (IASB).
In preparing those financial statements, the
directors are required to:
Select suitable accounting policies and then
apply them consistently.
Make judgements and estimates that are
reasonable and prudent.
Present information, including accounting
policies, in a manner that provides relevant,
reliable, comparable and understandable
information.
Provide additional disclosure when compliance
with the specific requirements of IFRS is
insufficient to enable users to understand the
impact of particular transactions, other events
and conditions on the group’s financial position
and financial performance.
State that applicable accounting standards
have been followed, subject to any material
departures disclosed and explained in the
parent company financial statements.
Prepare the financial statements on the going
concern basis unless it is inappropriate to
presume that the company will continue
in business.
The directors are responsible for keeping
adequate accounting records that disclose with
reasonable accuracy at any time the financial
position of the group and company and enable
them to ensure that the consolidated financial
statements comply with the Companies Act
2006 and the parent company financial
statements comply with the Companies Act
2006. They are also responsible for safeguarding
the assets of the group and company and hence
for taking reasonable steps for the prevention
and detection of fraud and other irregularities.
Having made the requisite enquiries, so far as the
directors are aware, there is no relevant audit
information (as defined by Section 418(3) of the
Companies Act 2006) of which the company’s
auditors are unaware, and the directors have
taken all the steps they ought to have taken to
make themselves aware of any relevant audit
information and to establish that the company’s
auditors are aware of that information.
The directors confirm that to the best of
their knowledge:
The consolidated financial statements,
prepared on the basis of IFRS as issued by the
IASB, IFRS adopted pursuant to Regulation
(EC) No 1606/2002 as it applies in the EU and
in accordance with the provisions of the
Companies Act 2006 as applicable to
companies reporting under international
accounting standards, give a true and fair view
of the assets, liabilities, financial position and
profit or loss of the group.
The parent company financial statements,
prepared in accordance with United Kingdom
generally accepted accounting practice, give a
true and fair view of the assets, liabilities,
financial position, performance and cash flows
of the company.
The management report, which is incorporated
in the strategic report and directors’ report,
includes a fair review of the development and
performance of the business and the position
of the group, together with a description of the
principal risks and uncertainties that they face.
Helge Lund
Chairman
22 March 2021
This page does not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
127
Directors’ statements continued
Non-operated joint ventures« and associates«
have not been dealt with as part of this
board process.
A description of the principal and emerging risks
facing the company, including those that could
potentially threaten its business model, future
performance, solvency or liquidity, is set out in
Risk factors on page 67. During the year, the
board undertook a robust assessment of the
principal and emerging risks facing the company.
The principal means by which these risks are
managed or mitigated are set out on page 65.
In assessing the risks faced by the company and
monitoring the system of internal control, the
board and the audit, safety, environment and
security assurance and geopolitical committees
requested, received and reviewed reports from
executive management, including management
of the business segments, corporate activities
and functions, at their regular meetings. A report
by each of these committees, including its
activities during the year, is set out on pages
92-102 and 105.
During the year, the committees, as relevant, also
met with management, the group head of audit
and other monitoring and assurance functions
(including group ethics and compliance, safety
and operational risk, group control, group legal
and group risk) and the external auditor.
Responses by management to incidents that
occurred were considered by the appropriate
committee or the board.
At a meeting in January 2021, the audit
committee considered reports from the group
risk function on the system of internal control and
the function’s categorisation of significant failings
and weaknesses. The audit committee also
considered a report from internal audit on their
assessment of bp’s systems of internal control
and risk management, based on audit work
conducted during 2020. In considering these
reports and assessments, the audit committee
noted that bp’s system of internal control and risk
management is designed to manage, rather than
eliminate, the risk of failure to achieve business
objectives and can only provide reasonable, and
not absolute, assurance against material
misstatement or loss.
At its meeting in March 2020, the board
considered the review undertaken by the audit
committee and the proposed disclosures
outlining the company’s risk management and
internal control systems prior to publication
of the annual report and accounts.
The scenarios that have been modelled are based
on the most severe but plausible outcomes and
associated costs are based on actual experience
where possible. The scenarios have been
considered individually and as a cluster of events.
They include:
A statement regarding the company’s internal
controls over financial reporting is set out on
page 327.
a significant process safety incident when
operating facilities, drilling wells or transporting
hydrocarbons.
Longer-term viability
In accordance with provision 31 of the Code,
the directors have assessed the prospects
of the company over a period significantly longer
than 12 months. The directors believe that,
notwithstanding bp’s new strategy and the
associated 2025 and 2030 net zero carbon
targets and aims that it set out in 2020, a viability
assessment period of three years remains
appropriate. This assessment is based on
management’s reasonable expectations of
the position and performance of the company
over this period and the targets and aims that
it has set out.
Our risk management system, described in how
we manage risk on page 64, outlines our risk
identification, assessment and management
approach for all risks, including our principal risks,
described on page 67.
Taking into account the company’s current
position and its principal risks, the directors have
a reasonable expectation that the company
will be able to continue in operation and meet
its liabilities as they fall due over the next
three years.
The directors’ assessment included a review of
the potential financial impact of, and the financial
headroom that could be available in the event
of, the most severe but plausible scenarios that
could threaten the viability of the company.
The assessment took into consideration the
robust financial position of the group and the
potential mitigations that management
reasonably believes would be available to
the company over this period. Mitigations
considered include use of cash, access to
debt facilities and credit lines, raising of capital,
reductions in capital expenditure, divestments
and dividend reductions.
a sustained significant decline in oil prices over
three years.
a significant cyber-security incident.
a loss of a significant market or producing
asset for six months.
The directors also considered the impact on
viability from an extended pandemic scenario,
as well as the potential risks associated with the
energy transition. They consider that the most
likely impacts of these risks are broadly captured
and modelled through the sustained low oil price
and loss of a producing asset scenarios.
In assessing the prospects of the company, the
directors noted that such assessment is subject
to a degree of uncertainty that can be expected
to increase looking out over time and, accordingly,
that future outcomes cannot be guaranteed or
predicted with certainty.
Going concern
In accordance with provision 30 of the Code,
the directors consider it appropriate to adopt the
going concern basis of accounting in preparing
the financial statements. The impact of COVID-19
and the current economic environment was
considered as part of the going concern
assessment. Forecast liquidity has been
assessed under a number of stressed scenarios,
including a significant decline in oil prices over the
12-month period. Reverse stress tests performed
indicated that the group will continue to operate
as a going concern for at least 12 months from
the date of approval of the financial statements
even if the Brent price fell to zero.
Fair, balance and understandable
The board considers the annual report and
financial statements, taken as a whole, is fair,
balanced and understandable and provides the
information necessary for shareholders to assess
the company’s position and performance,
business model and strategy.
This page does not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
128
bp Annual Report and Form 20-F 2020
Financial statements
The Thunder Horse platform is located in the
US Gulf of Mexico, around 150 miles southeast
of New Orleans, in over 6,000 feet of water.
Consolidated financial
statements of the bp group
Independent auditor’s reports
Group income statement
19. Inventories
20. Trade and other receivables
21. Valuation and qualifying accounts
22. Trade and other payables
130
155
Group statement of comprehensive income
156
23. Provisions
24. Pensions and other post-retirement benefits
25. Cash and cash equivalents
26. Finance debt
27. Capital disclosures and net debt
28. Leases
29. Financial instruments and financial risk factors
30. Derivative financial instruments
31. Called-up share capital
32. Capital and reserves
33. Contingent liabilities and legal proceedings
34. Remuneration of senior management
and non-executive directors
35. Employee costs and numbers
36. Auditor’s remuneration
37. Subsidiaries, joint arrangements and associates
38. Condensed consolidating information
on certain US subsidiaries
Group statement of changes in equity
Group balance sheet
Group cash flow statement
Notes on financial statements
1. Significant accounting policies
2. Non-current assets held for sale
3. Business combinations and other
significant transactions
4. Disposals and impairment
5. Segmental analysis
6. Revenue from contracts with customers
7. Income statement analysis
8. Exploration expenditure
9. Taxation
10. Dividends
11. Earnings per share
12. Property, plant and equipment
13. Capital commitments
14. Goodwill
15. Intangible assets
16. Investments in joint ventures
17. Investments in associates
18. Other investments
157
158
159
160
177
177
178
180
183
183
184
184
186
187
189
190
190
191
192
192
195
195
195
196
196
197
197
204
204
205
206
206
211
219
220
225
228
229
229
230
230
Supplementary information on
oil and natural gas (unaudited)
Oil and natural gas exploration and
production activities
Movements in estimated net proved reserves
Standardized measure of discounted future
net cash flows and changes therein relating
to proved oil and gas reserves
Operational and statistical information
Parent company financial
statements of BP p.l.c.
Company balance sheet
Company statement of changes in equity
Notes on financial statements
1. Significant accounting policies
2. Investments
3. Receivables
4. Pensions
5. Payables
6. Taxation
7. Called-up share capital
8. Capital and reserves
9. Financial guarantees
10. Share-based payments
11. Auditor’s remuneration
12. Directors’ remuneration
13. Employee costs and numbers
14. Related undertakings
232
238
253
256
259
260
261
261
265
266
267
270
271
271
272
272
273
273
273
273
274
bp Annual Report and Form 20-F 2020
129
Consolidated financial statements of the bp group
Independent auditor’s report to the members of BP p.l.c.
Report on the audit of the financial statements
1. Opinion
In our opinion:
• The financial statements of BP p.l.c. (the ‘parent company’) and its subsidiaries (the ‘group’) give a true and fair view of the state of the group’s and
of the parent company’s affairs as at 31 December 2020 and of the group’s loss for the year then ended.
• The group financial statements have been properly prepared in accordance with international accounting standards in conformity with the
requirements of the Companies Act 2006, International Financial Reporting Standards (IFRSs) as adopted by the European Union and IFRS as
issued by the International Accounting Standards Board (IASB).
• The parent company financial statements have been properly prepared in accordance with United Kingdom accounting standards (United Kingdom
generally accepted accounting practice), including Financial Reporting Standard (FRS) 101 ‘Reduced Disclosure Framework'.
• The financial statements have been prepared in accordance with the requirements of the Companies Act 2006 and, as regards the group financial
statements, Article 4 of the IAS Regulation.
We have audited the financial statements of BP p.l.c. which comprise the:
• Group income statement;
• Group statement of comprehensive income;
• Group and parent company statements of changes in equity;
• Group and parent company balance sheets;
• Group cash flow statement;
• Group related Notes 1 to 38 to the financial statements, including a summary of significant accounting policies; and
• Parent company related Notes 1 to 14 to the financial statements, including a summary of significant accounting policies.
The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and IFRSs as adopted by
the European Union and as issued by the IASB. As regards the parent company financial statements, the financial reporting framework that has been
applied in their preparation is applicable law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice),
including FRS 101 'Reduced Disclosure Framework'.
2. Basis for opinion
We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our responsibilities under those
standards are further described in the auditor’s responsibilities for the audit of the financial statements section of our report.
We are independent of the group and the parent company in accordance with the ethical requirements that are relevant to our audit of the financial
statements in the UK, including the Financial Reporting Council’s (the ‘FRC’s’) Ethical Standard as applied to listed public interest entities, and we have
fulfilled our other ethical responsibilities in accordance with these requirements. The non-audit services provided to the group and parent company for
the year are disclosed in Note 36 to the financial statements. We confirm that the non-audit services prohibited by the FRC’s Ethical Standard were not
provided to the group or the parent company.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
3. Summary of our audit approach
Key audit matters
The key audit matters that we identified in the current year were:
• COVID-19 and the resulting significant changes to the business environment;
• Potential impact of climate change and the energy transition;
• Impairment of upstream oil and gas property, plant and equipment (PP&E) assets;
• Write-off of exploration and appraisal (E&A) assets;
• Accounting for structured commodity transactions (SCTs) within the trading and shipping (T&S) function, and the valuation of
other level 3 financial instruments, where fraud risks may arise in revenue recognition;
• IT controls relating to financial systems; and
• Management override of controls.
This year we identified COVID-19 and the related significant changes to the business environment as a key audit matter, given
the consequential impact on the financial statements and the focus on this issue by management and by external stakeholders.
All other key audit matters are consistent with those we identified in the prior year.
Materiality
The materiality that we used for the group financial statements was $600 million (2019 $850 million) which was determined
based on net assets.
We adopted a different basis to determine the materiality used to audit the group financial statements this year. In the prior
year we used profit-based metrics but this year we used net assets due to the significant losses incurred as a consequence,
inter alia, of the COVID-19 pandemic and in particular the decrease in oil and gas prices.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
130
bp Annual Report and Form 20-F 2020
Financial statements
Scoping
Our scope covered 277 consolidation units (cons units). Of these, 173 were full-scope audits and the remaining 104 were
subject to specific procedures on certain account balances by component audit teams or the group audit team. These covered
82% of group revenue and 75% of PP&E. The remaining 642 cons unit were subject to other procedures, including conducting
analytical reviews, making inquiries, and evaluating and testing management's group-wide controls.
4. Conclusions relating to going concern
In auditing the financial statements, we have concluded that the directors’ use of the going concern basis of accounting in the preparation of the
financial statements is appropriate.
Our evaluation of the directors’ assessment of the group’s and parent company’s ability to continue to adopt the going concern basis of accounting
included:
• an assessment of whether material uncertainties existed that could cast significant doubt on the entity’s ability to continue as a going concern for at
least 12 months after the date of approval of the financial statements;
• an assessment of the financing facilities including nature of facilities, repayment terms and covenants;
• testing of clerical accuracy and appropriateness of the model used to prepare the forecasts;
• an assessment of the assumptions used in the forecasts;
• an assessment of management’s identified potential mitigating actions and the appropriateness of the inclusion of these in the going concern
assessment;
• an assessment of the historical accuracy of forecasts prepared by management;
• reperformance of management’s sensitivity analysis; and
• an assessment of the disclosures made within the financial statements
Based on our assessment, we concluded that the assumptions used by management were in the acceptable range and the disclosures made within
the financial statements were appropriate.
Based on the work we have performed, we have not identified any material uncertainties relating to events or conditions that, individually or
collectively, may cast significant doubt on the group's and parent company’s ability to continue as a going concern for a period of at least twelve
months from when the financial statements are authorised for issue.
In relation to the reporting on how the group has applied the UK Corporate Governance Code, we have nothing material to add or draw attention to in
relation to the directors’ statement in the financial statements about whether the directors considered it appropriate to adopt the going concern basis of
accounting.
Our responsibilities and the responsibilities of the directors with respect to going concern are described in the relevant sections of this report.
5. Key audit matters
Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial statements of the
current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) that we identified. These matters
included those which had the greatest effect on: the overall audit strategy, the allocation of resources in the audit; and directing the efforts of the
engagement team.
Throughout the course of our audit, we identify risks of material misstatement (‘risks’). We consider both the likelihood of a risk and the potential
magnitude of a misstatement in making the assessment. Certain risks are classified as ‘significant’ or ‘higher’ depending on their severity. The category
of the risk determines the level of evidence we seek in providing assurance that the associated financial statement item is not materially misstated.
These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not
provide a separate opinion on these matters.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
131
5.1 Impact of COVID-19 and the resulting significant changes to the business environment
Key audit matter
description
The COVID-19 pandemic has significantly impacted the oil and gas industry. The principal area in which this has
impacted bp is the demand destruction which led to low oil and gas prices in the year and an expectation that there will
be an enduring impact going forward reducing forecast oil and gas prices. Accordingly this has impacted certain key
estimates and judgements reliant on oil and gas prices. The lower oil and gas prices resulted in a loss for the year and
the lower oil and gas price forecasts have resulted in significant PP&E impairments and reduced the attractiveness of
developing certain E&A assets, leading to significant write-offs.
The related principal risks that we have identified for our audit are as follows:
• The forecast assumptions used in assessing the value of assets within bp’s balance sheet for impairment testing,
particularly oil and gas price assumptions relevant to upstream oil and gas PP&E assets, may not appropriately reflect
changes in supply and demand due to COVID-19 (see 'Impairment of upstream oil and gas PP&E assets' below);
• The E&A asset write-offs are not aligned with management’s intentions. In addition there is a risk around the
commercial viability of E&A assets that remain on the balance sheet (see 'write-off of E&A assets' below); and
• The unobservable inputs including long term commodity prices and the associated liquidity in the market, volatility
and correlations, which are critical in determining the valuation of level 3 financial instruments may not reflect how
market participants would reflect the effect, if any, of COVID-19 (see 'valuation of other level 3 financial instruments'
below).
Management also assessed the following potential risks that could arise from the impact of COVID-19 and the resulting
significant changes to the business environment, which we determined also to be audit risks:
• The liquidity of the business and future cash flow projections associated with the going concern assumption may not
reflect fully the impact of COVID-19. As a consequence, inter alia, of the COVID-19 pandemic and its implications,
management significantly increased liquidity, including securing a new $10 billion revolving credit facility in March
2020, issuing $6.8 billion of bonds in April 2020 and issuing $11.9 billion of hybrid bonds in June 2020. In addition
management performed a reverse stress test as set out in Note 1;
• The carrying value of the downstream PP&E refining assets may no longer be recoverable, due to changes in supply
and demand which have resulted from COVID-19. Furthermore, the useful economic lives of these assets could be
reduced (see 'Potential impact of climate change' below);
• Decommissioning obligations transferred to third parties as part of bp’s historical disposal transactions could
potentially return to bp under relevant laws and regulations in the event the buyer is unable to complete
decommissioning works due to the possibility of COVID-19 impacting their liquidity and financial stability;
• The increased risk of credit losses following increased counterparty credit risk due to commodity price volatility,
unprecedented demand destruction and bankruptcies of trading organisations. As described in Note 21, management
recognises that credit risk has increased since 31 December 2019 but as there has also been a significant reduction
in the group’s trade and other receivables balance, the total allowance for expected credit losses has not increased
significantly in the year;
• The shift to key business processes being performed virtually and the associated impact on the control environment.
In particular, in an environment of volatile commodity prices, there is an increased risk of non-compliance with
policies and procedures by traders within the T&S function, resulting in the risk of breaches in trader limits, as the
monitoring and surveillance of front office activities becomes more challenging; and
• During the year, a number of oil trading entities in Singapore have declared bankruptcies. After the bankruptcies,
allegations have been made that certain of the funding arrangements of these oil trading entities involved finance
schemes whereby funds were raised backed by assets that did not exist or were supported by fraudulent sales.
These finance schemes typically involved back-to-back intra-group arrangements transacted with an independent
third party. There is a risk that bp, as a significant participant in the oil trading sector in Singapore, may have been a
counterparty to such transactions, resulting in exposure to claims by the financiers to these oil trading entities.
The above considerations were a significant focus of management during the period which led to this being a matter
that we communicated to the Audit Committee, and which had a significant effect on the overall audit strategy. We
therefore identified this as a key audit matter.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
132
bp Annual Report and Form 20-F 2020
How the scope of our
audit responded to the
key audit matter
Financial statements
Overall response
We held discussions with management, Deloitte fraud specialists and within the Group engagement team to identify
the areas where we felt COVID-19 could have had a potential impact on the financial statements.
Audit procedures in respect of the three principal audit risks identified
Our audit response related to the three principal audit risks identified is set out under the key audit matters for
impairment of upstream oil and gas PP&E assets on page 136, the write-off of E&A assets on page 139 and the
valuation of other Level 3 instruments on page 140.
Other audit procedures performed
We performed further audit procedures, in addition to those discussed in section 4, to obtain sufficient appropriate audit
evidence regarding the appropriateness of management’s use of the going concern basis of accounting in the
preparation of the financial statements. These procedures included an assessment and reperformance of bp's reverse
stress test and a detailed analysis of the new financing agreements.
We challenged management’s analysis of potential exposures related to bp’s decommissioning obligations transferred
to third parties as part of disposal transactions, including comparing management’s assessment of each counterparty’s
liquidity and creditworthiness to third party support where available and holding discussions with bp's internal legal
counsel.
We assessed the credit risk of the portfolio and the associated valuation methodology to check the expected credit loss
allowance appropriately reflects the level of risk. In performing this assessment, we considered the impact of demand
destruction and price volatility on counterparties in specific market sectors such as Aviation, Independent refiners,
Retail Energy Providers, West African oil producers and regional commodity trading organisations.
We understood changes made to the control environment following the shift to remote working. Where there was a
change in the control, we challenged the appropriateness of these changes and assessed the operating effectiveness
of the control in light of these changes. We specifically obtained an understanding of the output of management’s
review of traders’ compliance with policies and procedures in light of remote working, including gain / loss alerts,
operational risk incidents reports and internal audit findings.
To respond to the oil trading entities’ bankruptcies, we altered the nature and extent of our procedures across seaborne
trading activity for the year ended 31 December 2020. Using data analytics, we have profiled the related transactions to
identify activity that exhibited certain characteristics, such as sale and purchase transactions at the same location with
similar settlement dates to determine the validity of such transactions. Our procedures to challenge the validity of the
transactions in this population included obtaining an understanding of the commercial rationale for a sample of the
contracts, obtaining independent confirmation or sighting third party evidence of bills of lading or other relevant
documentation that evidenced the sale of inventory.
We read the related disclosures in the Annual Report.
Key observations
Key observations in relation to oil and gas price assumptions used in upstream oil and gas PP&E assets impairment
tests, E&A asset write-offs and the valuation of other Level 3 instruments are set out in the relevant key audit matter
sections below.
We are satisfied with the results of the further audit procedures we performed in respect of going concern and consider
that management’s conclusion on the going concern assumption remains appropriate as set out in section 4 above.
Management’s reverse stress test as set out in Note 1 on page 161 indicates that the group will continue to operate as
a going concern for at least 12 months from the balance sheet date even if the Brent price fell to zero.
In respect of the decommissioning liabilities that transferred to third parties, we agree with management's conclusion
that no provision is required based on our assessment of the credit risk. We are satisfied with the disclosure set out in
Note 33.
We are satisfied with the results of our audit procedures in respect of credit risk and consider that management’s
expected credit loss valuation methodology and the input assumptions appropriately reflects the level of risk in the
current environment.
We found that the controls we tested generally operated effectively in the remote working environment and we
identified no issues of non-compliance with policies and procedures in the T&S function.
Our additional procedures to assess if the Group is exposed to any risk of exposure from finance schemes similar to
those that were used by the oil trading entities that declared bankruptcy did not highlight any additional issues.
We consider that management’s other disclosures in the Annual Report relating to COVID-19 are consistent with the
financial statements and our understanding of the business.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
133
5.2 Potential Impact of climate change and the energy transition (impacting PP&E, goodwill, intangible assets and provisions)
Key audit matter
description
Climate change impacts bp’s business in a number of ways as set out in the strategic report on pages 2-70 of the
Annual Report and Note 1 on page 160 of the financial statements. It represents a strategic challenge with its
implications becoming increasingly significant towards 2050 and beyond.
In February 2020 bp announced a new strategic intent which incorporates the ambition to become a ‘net zero’ company
by 2050 or sooner. Further details were announced in August 2020 and September 2020. This led to revised intentions
in respect of E&A assets and a significant internal restructuring. In addition, as a consequence of the COVID-19
pandemic, bp revised its oil and gas price forecasts significantly downwards.
Whilst many of bp’s oil and gas properties, and refining assets, are long term in nature, none are being amortised over a
period that extends beyond 2050. At current rates of depreciation, depletion and amortisation (DD&A), the average
remaining depreciable life of the upstream PP&E is seven years and the downstream PP&E is twelve years.
Accordingly, the related principal risks that we have identified for our audit are as follows:
• Forecast assumptions used in assessing the value of upstream assets within bp’s balance sheet for impairment
testing, particularly oil and gas price assumptions relevant to upstream oil and gas PP&E assets, may not
appropriately reflect changes in supply and demand due to climate change and the energy transition (see 'impairment
of upstream PP&E' below); and
• Recoverability of E&A assets included within bp’s balance sheet where the investment required in order to develop
particular projects into producing oil and gas PP&E assets might not be sanctioned by the board in future due to
climate change considerations or a potential development may not be considered to be economic due to the impact
of climate change and the energy transition on oil and gas prices (see 'write-off of exploration and appraisal (E&A)
assets' below).
Management also assessed the following potential risks that could arise from climate change considerations:
• The carrying value of goodwill may no longer be recoverable and therefore may need to be impaired. The material
upstream goodwill balance is recorded and tested at the segment level. The most significant assumption in the
goodwill impairment test affected by climate change relates to future oil and gas prices (see 'impairment of upstream
PP&E' below). Given the significant headroom in the goodwill impairment test, management identified no other
assumption that could lead to a material misstatement of goodwill due to the energy transition and other climate
change factors. Disclosures in relation to sensitivities for goodwill are included within Note 14 on pages 190-191. The
total goodwill balance as at 31 December 2020 is $12.5 billion, of which $7.8 billion relates to the upstream segment.
The downstream segment has a goodwill balance of $4.7 billion, of which the most significant element is $2.9 billion
relating to the Lubricants business. Notwithstanding the expected global transition to electric vehicles which may
reduce demand for Lubricants, management has assessed due to the substantial headroom in the most recent
impairment test (as described in Note 14), the likelihood that the recoverable amount of goodwill is less than its
carrying value is remote.
• Provisions for decommissioning and asset retirement obligations of upstream PP&E may need to be brought forward
with a resulting increase in the present value of the associated liabilities. As described in Note 1, the impact of a two-
year change to the timing of expected future decommissioning expenditures would not have a material impact on the
decommissioning provision reported in the current period;
• The carrying value of the downstream PP&E refining assets may no longer be recoverable, due to changes in supply
and demand which arise as a consequence of COVID-19, climate change and the energy transition, for example the
adoption of electric vehicles in markets where bp has significant fuel refining activity. Management identified
impairment indicators at certain of the most material downstream refining assets, as a result of a combination of
factors including the onset of COVID-19 and the resulting reduced demand for fuels. Accordingly, impairment tests
were performed to assess the recoverability of the refinery asset carrying values. The most significant assumptions
in the impairment tests are the assumed future refining margins, and demand profiles for fuel in the markets served
by individual refineries. As disclosed in Note 1 to the accounts on page 160, management concluded that no material
impairments were required on its downstream assets.
• The useful economic lives of the group’s downstream refining assets may be shortened as society moves towards
'net zero' emissions targets and bp seeks to achieve its net-zero ambition, such that the depreciation charge is
materially understated. As disclosed in Note 1 to the accounts on page 160, management concluded that demand for
refined products is expected to remain strong over the useful life of its existing assets and hence no changes to the
useful economic lives of its refinery assets was required.
• Provisions for decommissioning downstream refining assets, previously not generally recognised on the basis that
the potential obligations cannot be measured given their indeterminate settlement dates, might need to be
recognised if reductions in demand due to climate change and exacerbated by COVID-19 curtail their operational
lives. As disclosed in Note 1 to the accounts on page 171 management concluded that, although obligations may
arise if refineries cease manufacturing operations, they would only be recognised at the point when sufficient
information became available to determine potential settlement dates. In addition, as noted above, management
concluded that demand for refined products is expected to remain strong in areas served by its existing refineries.
Accordingly, other than where a decision has been made to cease refining operations, no triggers for assessing the
need to record a decommissioning provision have been identified;
• Climate change-related litigation brought against bp, as disclosed in Note 33 to the financial statements, may lead to
an outflow of funds requiring provision in the current year; and
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
134
bp Annual Report and Form 20-F 2020
How the scope of our
audit responded to the
key audit matter
Financial statements
• The announcement of the restructuring of the group and the resulting risk that the costs associated with the
restructuring are not appropriately provided for and that following the reduction in size of the workforce the internal
controls in place are not appropriately designed, implemented and operating effectively.
The above considerations were a significant focus of management during the period which led to this being a matter
that we communicated to the audit committee, and which had a significant effect on the overall audit strategy. We
therefore identified this as a key audit matter.
Overall response
We held discussions with management, with Deloitte Climate Change specialists and within the Group engagement
team to identify the areas where we felt climate change could have a potential impact on the financial statements.
We also established a climate change steering committee comprising a group of senior partners with specific climate
change and technical audit and accounting expertise within Deloitte to provide an independent challenge to our key
decisions and conclusions with respect to this area.
Audit procedures in respect of the three principal audit risks identified
The audit response related to the two principal audit risks identified is set out under the key audit matters for
impairment of upstream oil and gas PP&E assets on page 136-8 and the write-off of exploration and appraisal assets on
page 139.
Other audit procedures performed
We performed procedures to satisfy ourselves that, other than future oil and gas price assumptions, there were no
other assumptions in management’s upstream goodwill impairment test to which reasonably possible changes could
cause goodwill to be materially misstated. We obtained evidence which supported management’s conclusion that
goodwill relating to downstream segment activities is not impaired.
We challenged management’s assertion that the impact of potential changes to upstream decommissioning dates
would not have a material impact on the amounts reported in the current period by assessing the analysis of
decommissioning timing, and conducting sensitivity analysis as part of our audit procedures.
We challenged the results of the impairment testing of downstream PP&E refining assets by considering internal and
external market studies of future supply and demand, and conducting sensitivity analysis. For those refining assets
where impairment triggers were identified, we tested the mathematical completeness and accuracy of the impairment
models and assessed the appropriateness of key assumptions and inputs. We also tested management’s internal
controls over the impairment tests.
We challenged management’s assertion that no changes are required to the assessed useful economic lives of refining
assets as a consequence of COVID-19 and climate change factors. In doing this, we obtained third party reports
assessing future refined petroleum product demand for those countries which are included in our group full audit scope
for downstream. The future demand forecasts were prepared under a range of scenarios including scenarios noted as
being consistent with achieving the 2015 COP 21 Paris agreement goal to limit temperature rises to well below 2°C
('Paris 2°C Goal').
We challenged management’s analysis which supported their judgement that no decommissioning provisions should
be recognised in respect of refineries where there is ongoing activity and management has no intention to cease these
activities. In doing so we considered the third party forecasts referenced above which, for countries included in our
group full audit scope for downstream, show that demand for refined petroleum products is expected to remain
significant for at least the current remaining useful economic lives of the refineries, even under scenarios consistent
with the Paris 2°C Goal.
With regard to climate change litigation, we designed procedures specifically to respond to the risks that provisions
could be understated or that contingent liability disclosures may be omitted or be inaccurate including:
• Holding discussions with the group general counsel and other senior bp lawyers regarding climate change matters;
• Conducting a search for climate change litigation and claims brought against the group; and
• Making written inquiries of, and holding discussions with, external legal counsel advising bp in relation to climate
change litigation.
We held discussions with management and tested the controls in respect of the restructuring provision. We performed
substantive procedures to assess whether the provision was appropriately recognised as required by International
Accounting Standard (IAS) 37 ‘Provisions, Contingent Liabilities and Contingent Assets’.
We read the other information included in the Annual Report and considered (a) whether there was any material
inconsistency between the other information and the financial statements; or (b) whether there was any material
inconsistency between the other information and our understanding of the business based on audit evidence obtained
and conclusions reached in the audit.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
135
Key observations
Key observations in relation to oil and gas price assumptions used in upstream oil and gas PP&E asset impairment
tests, and the recoverability of exploration and appraisal assets including the impacts of climate change, are set out in
the relevant key audit matter below.
We are satisfied with the disclosures around the sensitivity analysis performed in respect of goodwill, and that the
significant headroom is indicative that the energy transition and other climate change factors could not lead to a material
misstatement of this balance.
We are satisfied that the disclosure in Note 1 in respect of the impact of timing on decommissioning provisions is
appropriate.
We are satisfied with the results of our procedures relating to the carrying value of refining assets and that no
impairments are required.
Based on the market studies we read, we are satisfied with the results of our procedures relating to the assessment of
useful economic lives, and therefore depreciation charges, for downstream refining assets.
We noted that the third party demand forecasts generally showed a reduction in forecast long term demand, under a
Paris 2°C Goal scenario, compared to the equivalent forecasts in the prior year. Nevertheless, we are satisfied that it is
not possible to estimate reliably a settlement date for any decommissioning obligations prior to a decision being made
to cease refining operations and that therefore no triggers have arisen that would require a decommissioning provision
to be recorded for the group’s operating refinery assets.
Based on the audit evidence obtained both from internal and external legal counsel, we were satisfied with
management’s assertion that no provision should currently be made in respect of climate change litigation. We read
management’s disclosure of the contingent liabilities in respect of these matters and concluded that the disclosures are
appropriate.
We found the controls relating to the restructuring provision to be operating effectively and are satisfied that the
restructuring provision is recorded in accordance with IAS 37, ‘Provisions, Contingent Liabilities and Contingent Assets’.
We are satisfied that management’s other disclosures in the Annual Report relating to climate change are consistent
with the financial statements and our understanding of the business.
5.3 Impairment of upstream oil and gas PP&E assets
Key audit matter
description
The group balance sheet at 31 December 2020 includes PP&E of $115 billion (2019 $133 billion), of which $74 billion
(2019 $90 billion) is oil and gas properties within the upstream segment.
Management’s best estimate of oil and gas price assumptions for value–in-use impairment tests were revised
downwards during 2020 compared to the prior year assumptions, as set out in Note 1 on page 161. The downward
revisions reflect an expectation that the aftermath of the COVID-19 pandemic will accelerate the pace of transition to a
lower carbon economy and energy system. Given the significance of these revisions, management tested all upstream
CGUs for impairment.
Management recorded $12.9 billion (2019 $6.8 billion) of pre-tax upstream CGU impairment charges, in large part due to
the oil and gas prices revisions detailed above, and $0.1 billion of pre-tax upstream CGU impairment reversals (2019
$0.1 billion). Further information has been provided in Note 1 on page 160 and Note 4 on page 179.
Through our audit risk assessment procedures, we identified three key management estimates in management’s
determination of the level of impairment charge and/or reversal to record. These are:
• Oil and gas prices - bp’s oil and gas price assumptions have a significant impact on many CGU impairment
assessments performed across the upstream segment, and are inherently uncertain. As noted above, the estimation
of future prices is subject to increased uncertainty given climate change, the global energy transition and the impact
of COVID-19. There is a risk that management do not forecast reasonable 'best estimate' oil and gas price forecasts
when assessing CGUs for impairment, leading to material misstatements. These price assumptions are highly
judgmental and are pervasive inputs to most upstream impairment tests, such that any misstatements would also
aggregate.
• Discount rates - Given the long timeframes involved, certain CGU impairment assessments are sensitive to the
discount rate applied. Discount rates should reflect the return required by the market and the risks inherent in the
cash flows being discounted. There is a risk that management do not assume reasonable discount rates, adjusted as
applicable for country risks and relevant tax rates, leading to material misstatements. Determining a reasonable
discount rate is highly judgmental and, consistent with price assumptions above, the discount rate assumption is also
a pervasive input across upstream impairment tests, before adjustments for asset specific risks and tax rates, such
that any misstatements would also aggregate.
• Reserves and resources estimates - A key input to certain CGU impairment assessments is the oil and gas
production forecast, which is based on underlying reserves estimates and field specific development assumptions.
Certain CGU production forecasts include specific risk adjusted resource volumes, in addition to proved or probable
reserves estimates, that are inherently less certain than reserves; and assumptions related to these volumes can be
particularly judgemental. There is a risk that material misstatements could arise from unreasonable production
forecasts for individually material CGUs and/or from the aggregation of systematic flaws in bp’s reserves and
resources estimation policies across the segment.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
136
bp Annual Report and Form 20-F 2020
Financial statements
We identified certain individual CGUs with a total carrying value of $32.1 billion (2019 $12.3 billion) which we
determined would be most at risk of material impairment charges or reversals as a result of a plausible change in the oil
and gas price assumptions. We identified that a subset of these CGUs were also sensitive to the discount rate
assumption. Accordingly, we identified these as significant audit risks.
We also identified CGUs with a further $16.0 billion (2019 $33.4 billion) of combined carrying value which were less
sensitive. We identified these as a higher audit risk as they would be potentially at risk, in aggregate, to a material
impairment or reversal by a plausible change in some or all of the key assumptions.
Further information regarding these sensitivities is given in Note 1 on page 167.
How the scope of our
audit responded to the
key audit matter
We tested management’s key internal controls over the estimation of oil and gas prices, discount rates and reserve and
resources estimates, as well as key internal controls over the performance of the impairment assessments where we
identified audit risks. In addition, we conducted the following substantive procedures.
Oil and gas prices
• We independently developed a reasonable range of forecasts based on external data obtained, against which we
compared management’s oil and gas price assumptions in order to challenge whether they are reasonable.
• In developing this range we obtained a variety of reputable and reliable third party forecasts, peer information and
other relevant market data.
• In challenging management's price assumptions, we considered the extent to which they and each of the forecast
pricing scenarios obtained from third parties reflect the impact of lower oil and gas demand due to climate change,
the energy transition and COVID-19.
• We specifically analysed third party forecasts stated as being, or interpreted by us as being, consistent with achieving
the Paris 2°C Goal and considered whether they presented contradictory audit evidence.
• We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of oil and gas price
assumptions to reduced demand scenarios whether due to climate change or other reasons.
Discount rates
• We independently evaluated bp’s discount rates used in impairment tests with input from Deloitte valuation
specialists, against relevant third party market and peer data.
• We assessed whether specific country risks and tax adjustments were reasonably reflected in bp’s discount rates.
• We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of discount rate
assumptions.
Reserves and resources estimates
With the assistance of Deloitte oil and gas reserves specialists we:
• assessed bp’s reserves and resources estimation methods and policies;
• assessed, guided by our risk assessment, how these policies had been applied to a sample of bp’s reserves and
resources estimates which included those that we judged to represent the greatest risk of material misstatement;
• read a sample of reports provided by management’s external experts and assessed the scope of work and findings of
these third parties;
• assessed the competence, capability and objectivity of bp’s internal and external reserves experts, through
understanding their relevant professional qualifications and experience;
• compared the production forecasts used in the impairment tests with management’s approved reserves and
resources estimates, those estimates having been subjected to the controls that we had tested; and
• performed a retrospective assessment to check for indications of estimation bias over time.
Other procedures
• We challenged management’s CGU determinations, and considered whether there was any contradictory evidence
present.
• We validated that bp’s impairment methodology was acceptable under IFRS and tested the integrity and mechanical
accuracy of certain impairment models based on our risk assessment.
• We challenged other CGU specific valuation input assumptions, including but not limited to material cost and tax
forecasts, by comparing forecasts to approved internal and third party budgets, development plans, independent
expectations and historical actuals.
• Where relevant, we assessed management’s historical forecasting accuracy and whether the estimates had been
determined and applied on a consistent basis across the group.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
137
Key observations
Oil and gas prices
We determined that bp’s oil and gas price impairment assumptions are reasonable when compared against a range of
third party forecasts that we identified as being appropriate for this purpose, noting in particular that they had been
updated for COVID-19. In forming this view, we included each forecaster’s 'base case', 'central case' or 'most likely'
estimate. For the purpose of PP&E impairment tests, management is required under IAS 36 to apply its current 'best
estimate' of future oil and gas prices.
We further observed that, as well as publishing a 'base case', 'central case' or 'most likely' estimate, certain third party
price forecasters published other price forecasts including some that were stated as, or were interpreted by us as
being, 'Paris 2°C Goal' scenarios. These were typically the lowest of all scenarios from those third parties and we
observed that none of those third party forecasters described their 'Paris 2°C Goal' scenarios as their 'base case',
'central case' or 'most likely' estimate. We noted that not all of these third parties had updated their forecasts for
COVID-19 although, unlike for the ‘best estimate forecasts’ which had typically been reduced significantly post
COVID-19, it is less evident that ‘Paris 2°C forecasts’ would need changing as a result of COVID-19 at least in the longer
term and we noted certain updated forecasts that had not changed significantly. Accordingly, in respect of Paris 2°C
price scenarios only, we continued to place some weight on certain pre-COVID-19 third party forecasts.
Management note on page 160 that they consider their central price assumptions to be broadly in line with a range of
transition paths consistent with the goals of the Paris climate change agreement. We observed that for oil, whilst being
within the lower half of our range of 'best estimate' forecasts as described above, bp’s price assumptions were overall
at the top end of our range of 'Paris 2°C Goal' scenarios. For gas, as well as being within and towards the low end of
our range of 'best estimate' forecasts as described above, bp’s price assumptions were within and towards the higher
end of our range of 'Paris 2°C Goal' scenarios. We also noted certain other reputable third party sources that set out or
implied even higher prices under a Paris 2°C scenario. Accordingly, we consider management’s view as set out above
to be reasonable.
We reviewed the disclosures included in Note 1 to the accounts in respect of price assumptions, including the
sensitivity analysis presented therein. We observed that management’s downside sensitivity, in which oil and gas
prices are 10% lower than the best estimate in all future periods, is comfortably within a range of third party Paris 2°C
Goal gas price forecasts. For oil, management’s downside sensitivity is comfortably within a range of Paris 2°C Goal
forecasts in the period to 2028, but towards the top end of that range by 2050.
Discount rates
bp’s post-tax nominal 6% weighted average cost of capital, being the starting point for setting discount rates used for
impairment testing, was within the independent range calculated by our Deloitte valuation specialists.
We were also satisfied with the calculation of country risk premia. Accordingly, we are satisfied with the discount rates
used in the impairment testing.
Reserves and resources estimates
We found that the production forecasts used in the impairment tests that we tested were reasonable and appropriately
risked where applicable, for the purposes of management’s impairment tests.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
138
bp Annual Report and Form 20-F 2020
5.4 Write-off of E&A assets, included within 'Intangible assets' within the Group balance sheet
Key audit matter
description
The group capitalises E&A expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and Evaluation of
Mineral Resources'. At 31 December 2020, $4.1 billion (2019 $14.1 billion) of E&A expenditure was carried on the
group balance sheet.
Financial statements
E&A activity carries inherent risk and a significant proportion of projects fail, requiring the write-off or impairment of the
related capitalised costs when the relevant criteria in IFRS 6 and bp’s accounting policy are met.
Furthermore, similar to upstream PP&E assets discussed above, E&A assets are also potentially exposed to climate
change, the global energy transition, and COVID-19, in that a greater number of E&A projects may not proceed as a
consequence of lower forecast future demand and oil and gas pricing, lower appetite by management and the board to
allocate capital to certain projects, and/or increased objections from stakeholders to the development of certain
projects.
As a result of bp’s revised strategy announced in 2020, including a reduced capital frame, a net-zero carbon ambition
and a decision not to explore in new countries, and reflecting lower oil and gas price assumptions, management
identified IFRS 6 impairment indicators at a number of upstream’s largest E&A assets during the year. This led to
management recording $9.9 billion of pre-tax E&A write-offs and impairments during 2020 (2019 $0.6 billion), detailed
further in Notes 1 and 8 on pages 164 and 184.
The determination of when E&A costs should be written off or impaired, or retained on the balance sheet as E&A
assets, can be complex and require significant judgement from management in assessing this. There is a risk that
certain capitalised E&A costs are written off or impaired when they should not have been, due to inappropriate and/or
inconsistent application of IFRS 6 impairment criteria and bp’s accounting policy, leading to material misstatements.
There is also a risk that E&A costs remain capitalised on the balance sheet which ought to have been written off or
impaired, leading to material misstatements.
We identified significant audit risks for the individually material E&A write-offs and impairments recorded in 2020,
specifically the Kaskida and Tigris (Paleogene) licenses that were the largest part of the $2.5 billion Gulf of Mexico
write-downs, the Terre de Grace oil sands project that was the largest part of the $2.5 billion Canada write-downs and
the BM-C-35, BM-C-32 (Itaipu) & BM-C-30 (Wahoo) licenses that were the largest part of the $2.1 billion Brazil write-
downs. We also identified higher risks in relation to certain other 2020 E&A write-offs and impairments recorded; and
higher risks at certain assets within the $4.1 billion of E&A costs that remain capitalised under IFRS 6 at 31 December
2020.
How the scope of our
audit responded to the
key audit matter
We obtained an understanding of the group’s E&A assessment processes and tested management’s key internal
controls. This included the new key internal controls operated by management for the key decisions taken as a result of
bp’s new strategy, which when taken together with the lower forecast oil and gas prices, led to a large portion of the
material write-offs and impairments recorded during 2020.
We challenged management’s key E&A judgements, with regards to the impairment criteria of IFRS 6 and bp’s
accounting policy. We corroborated key internal and external evidence relevant to significant write-offs and the assets
that remained on the balance sheet. This included analysing evidence of future E&A plans, budgets and capital
allocation decisions, assessing management’s key accounting judgement papers, holding discussions to challenge top
level operational and finance management on the key judgements taken and reading meeting minutes, license
documentation and evidence of active dialogue with partners and regulators including negotiations to renew licences or
modify key terms, and external press releases.
For E&A assets that were written off or impaired by management in 2020, including in particular those based upon
decisions taken in line with management’s new strategy, we considered whether evidence (and potential contradictory
evidence) about activity in the year, future budgeted expenditure and exploration/appraisal plans, including plans and
expectations for licence relinquishment or retention, were consistent with the decisions taken by management to write-
off or impair these assets.
We assessed whether management had consistently applied IFRS 6 and bp’s accounting policy to impairment
assessments, taking account of in year judgements and historical look back considerations, and the relevant facts and
circumstances of specific E&A assets.
When considering capital allocation decision making, we considered whether the progression of any projects that
remain on the balance sheet would be inconsistent with elements of bp’s new strategy and in particular its net zero
carbon commitments.
We concluded that the key assumptions had been appropriately determined and the judgements management had
made were appropriately supported. No inappropriate or untimely E&A impairment charges or write-offs were
identified, nor was the need for any additional impairments or write-offs identified from the work we performed.
We also confirmed management's view that they did not consider that the progression of any of their E&A assets
would be inconsistent with bp’s current strategy and management’s capital frame and capital allocation intentions.
Key observations
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
139
5.5 Accounting for structured commodity transactions (SCTs) within the trading and shipping (T&S) function and the valuation of other
Level 3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all financial statement accounts,
in particular finance debt)
Key audit matter
description
In the normal course of business, T&S enters into a variety of transactions for delivering value across the group’s supply
chain. The nature of these transactions requires significant audit effort to be directed towards challenging
management’s valuation estimates or the adopted accounting treatment.
We have undertaken an analysis of the portfolio composition and revisited our risk assessment throughout the year
focussing particularly on the impact of COVID-19 on the valuation assertion. This process has provided us with a deeper
understanding of the impact of market volatility, demand destruction and the changing structure of the markets in
which bp operates.
Accounting for structured commodity transactions:
T&S may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an
arrangement having one of the following features:
• Two or more counterparties with non-standard contractual terms;
• Multiple commodity-based transactions; and/or
• Contractual arrangements entered into in contemplation of each other.
SCTs are often long-dated, can have a significant multi-year financial impact, and may require the use of complex
valuation models or unobservable inputs when determining their fair value, in which case they will be classified as level
3 financial instruments under IFRS 13, ‘Fair Value Measurement’.
Accounting for SCTs is typically complex and involves significant judgment, as these transactions often feature multiple
elements that will have a material impact on the presentation and disclosure of these transactions in the financial
statements and on key performance measures, including in particular the classification of liabilities as finance debt.
Accordingly, we have identified the accounting for SCTs as a significant audit risk.
Level 3 financial instruments:
Unlike other financial instruments whose values or inputs are readily observable and therefore more easily
independently corroborated, there are certain transactions for which the valuation is inherently more subjective due to
the use of either complex valuation models and/or unobservable inputs. These instruments are classified as level 3
financial assets or liabilities. This degree of subjectivity also gives rise to a risk of potential fraud through management
incorporating bias in determining fair values. Accordingly, we have identified these as a significant audit risk.
As at 31 December 2020, the group’s total financial assets and liabilities measured at fair value were $12.7 billion (2019
$10.5 billion) and $8.4 billion (2019 $8.8 billion), of which level 3 derivative financial assets were $6.4 billion (2019 $5.5
billion) and level 3 derivative financial liabilities were $5.3 billion (2019 $4.4 billion).
How the scope of our
audit responded to the
key audit matter
Accounting for SCTs
For structured commodity transactions, we:
• Tested controls related to the accounting for complex transactions.
• Developed an understanding of the commercial rationale of the transactions through reading transaction documents
and executed agreements, and discussions with management.
• Performed a detailed accounting analysis for a sample of SCTs involving significant day one profits, deferred working
capital arrangements, offtake arrangements and/or commitments. We confirmed that any day one profits were
appropriately deferred.
For SCTs which were identified during 2018 and 2019 and that continue through 2020, we have refreshed our
assessment in 2020 taking account of any amendments to the contracts.
To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists
within the audit team.
Level 3 financial instruments:
To address the complexities associated with auditing the value of level 3 financial instruments, the engagement team
included valuation specialists having significant quantitative and modelling expertise to assist in performing our audit
procedures. Our valuation audit procedures included the following control and substantive procedures:
• We tested the group’s valuation controls including the:
◦ Model certification control, which is designed to review a model’s theoretical soundness and the
appropriateness of its valuation methodology; and
◦
Independent price verification control, which is designed to review the appropriateness of valuation inputs that
are not observable and are significant to the financial instrument’s valuation.
• We performed substantive valuation testing procedures at interim and year-end balance sheet dates, including:
◦ Comparing management’s input assumptions against the expected assumptions of other market participants
and observable market data;
◦ Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a
consistent framework is applied across the business period over period; and
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
140
bp Annual Report and Form 20-F 2020
◦ Engaging a Deloitte valuations specialist to challenge models, develop fair value estimates and verify
consistency in management’s modelling and input assumptions throughout the year. Our independent estimates
were established using independently sourced inputs (where available). We evaluated whether the differences
between our independent estimates and management’s estimates were within a reasonable range. In situations
where we utilised management’s inputs, these were compared to external data sources to determine whether
they were reasonable.
Financial statements
Key observations
We assessed the features of the SCTs and determined that the accounting adopted for each of them was appropriate
and in accordance with IFRS.
We concluded that management’s valuations relating to level 3 instruments were appropriate.
We did not identify any indications of inappropriate misrepresentation of revenue recognition in the transactions,
valuation estimates or accounting entries that we tested.
We did not identify any issues in our testing of the controls related to the accounting for complex transactions and
found these to be operating effectively.
5.6 IT controls relating to financial systems (potentially impacting all financial statement accounts)
Key audit matter
description
The group’s financial systems environment is complex, with 113 separate systems scoped as being relevant for the
group audit.
Due to the reliance on financial systems within the group, IT controls which support these systems are critical to
maintaining an effective control environment.
We identified IT control deficiencies in two key areas.
User Access Management:
In 2018 and 2019 we identified a number of deficiencies relating to user access management, both within the group
and at the group’s IT service organizations (together ‘access deficiencies’). Management implemented a remediation
and mitigation programme throughout 2019 and 2020, which addresses the vast majority of these user access
deficiencies. To the extent the controls were not remediated management designed and tested mitigating controls for
the period prior to the successful remediation of each control. The remediation program is substantially complete but
will continue into 2021 because certain deficiencies are dependent on other bp change programmes including the
completion of a new identity management system implementation.
The access deficiencies identified increase the risk that individuals across bp had inappropriate access during the
period. This results in an increased risk that data, automated controls and reports from the affected systems are not
reliable. The access deficiencies impact all components within the scope of our group audit.
Change Management:
We identified in 2019 deficiencies around the bp IT change management process. In 2020, management continued to
identify further inconsistent implementation of the minimum change management controls, specifically around approval
of changes and evidence of testing. Management has continued to perform retrospective mitigation throughout 2020.
Furthermore, in 2020 bp increased its use of the DevOps model for managing change releases. DevOps is an accepted
way of managing change which bridges the development and operations process with the aim of reducing change
timelines and enabling agility. The implementation of DevOps allows user privileges to be extended so developers are
also able to implement changes, a key segregation of duties (SoD) conflict within the change management lifecycle. To
manage this key SoD conflict, additional controls need to be implemented to ensure a developer cannot undermine the
change management process through the ability to develop and implement the same change.
We identified that 25 applications using the DevOps change model did not have appropriate preventative SoD controls
in place. For the systems we identified, this issue was remediated and mitigated in 2020 by management.
Management has completed a root cause analysis and is implementing a sustainable forward looking governance and
control plan to manage the risk around DevOps.
The change management deficiencies identified increase the risk of inappropriate or untested changes being made
which could negatively impact the way a system operates and accordingly, the ongoing integrity of the controls, reports
and data within key financial systems.
The change management issues identified impact all components within the scope of our group audit.
Both the user access management controls and the controls over change management are pervasive to the group’s
operations and accordingly the level of risk ascribed to our work in this area is dependent on the nature and complexity
of the control itself and the risks addressed by the control.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
141
How the scope of our
audit responded to the
key audit matter
We obtained an understanding of management’s processes and relevant financial systems, and tested the associated
general IT controls and automated business controls. We also tested the integrity of key reports. In responding to the
identified deficiencies our IT specialists:
User Access Management:
Performed procedures to:
• Test the controls that management has implemented or re-designed in order to remediate the deficiencies;
• Assess and test the mitigating controls that management identified, including directly testing those controls operated
by IT service organizations; and
• Determine the impact that utilizing inappropriate levels of access could feasibly have had on the affected systems
including assessing the likelihood of inappropriate user access impacting the financial statements. We tested controls
implemented by management to identify instances of the use of inappropriate access.
Change Management:
Performed independent testing over:
• Mitigating controls identified by management to confirm the integrity of the change management process. These
procedures were designed to address the likelihood and impact of inappropriate or untested changes being
implemented; and
• Management’s mitigation procedures, which demonstrated that segregation of duties across the development and
implementation of change, for those systems impacted by DevOps was retained. These procedures were designed
to address the likelihood and impact that a single user could undermine the bp change management process through
creation and implementation of a change.
Key observations
Our testing confirmed that the remediated controls were operating effectively.
We also found the mitigating controls management performed to be operating effectively. In addition, our independent
testing to demonstrate whether the access and change management deficiencies were exploited during the year, did
not identify instances of inappropriate access usage or change implementation.
Accordingly, we were satisfied with the results of the remediation to date and the mitigation such that we continued to
adopt an audit approach which places reliance on the operating effectiveness of financial controls. Under our
methodology, this enables us to apply lower sample sizes in our substantive testing.
Management continues to work to remediate fully the access and change management deficiencies identified.
5.7 Management override of controls (potentially impacting all financial statement accounts)
Key audit matter
description
We conducted an assessment of the fraud risks arising from management override of controls by considering potential
areas where the group’s financial statements could be manipulated, including:
• Inappropriate accounting estimates and judgements;
• The posting of fictitious or fraudulent journal entries; or
• Accounting for significant unusual transactions arising from changes to the business.
In performing this assessment we considered pressures or incentives to achieve certain IFRS or non-GAAP measures
due to the remuneration arrangements of people in Financial Reporting Oversight Roles (FRORs), including
management and senior executives as well as other opportunities or incentives which could exist in light of the current
environment;
During our 2018 and 2019 audits we identified control deficiencies relating to the posting of accounting journal entries
at the components where testing was performed. Management’s programme to remediate these deficiencies through
the design of processes and controls in respect of the posting and review of manual journals was completed by the end
of 2020 but has been impacted by the IT Control issues outlined in section 5.6 above. Accordingly, these control
deficiencies remained during 2020 and we tested the mitigating controls which had been identified by management
during the previous years’ audits or other appropriate controls to mitigate these deficiencies. We expect to be testing
the remediated journal controls in 2021 once the related IT control deficiencies have been remediated.
This had a significant bearing again this year on the allocation of audit resources and has been discussed with the audit
committee throughout the year. Accordingly, we identified this as a key audit matter.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
142
bp Annual Report and Form 20-F 2020
How the scope of our
audit responded to the
key audit matter
Key observations
Financial statements
We tested the mitigating controls that management identified as responding to the risk of fraudulent journal entries.
In addition, we:
• Made inquiries of individuals involved in the financial reporting process about inappropriate or unusual activity relating
to the processing of journal entries and other adjustments.
• Identified and tested relevant entity-level controls, in particular those related to the bp Code of Conduct,
whistleblowing (bp OpenTalk) and controls monitoring financial reporting processes and financial results.
• Used our data analytics tools to select journal entries and other adjustments made at the end of a reporting period or
otherwise having characteristics associated with common fraud schemes for testing.
• Tested journal entries and other adjustments recorded in the general ledger throughout the period, with a particular
focus on adjustments that occur late in the financial close process.
We have assessed accounting estimates for bias and evaluated whether the circumstances producing the bias, if any,
represent a risk of material misstatement due to fraud. A number of the most significant estimates are covered by the
other Key Audit Matters set out above. This assessment included:
• Evaluating whether the judgements and decisions made by management in making the accounting estimates
included in the financial statements, even if they are individually reasonable, indicate a possible bias on the part of
bp's management that may represent a risk of material misstatement due to fraud; and
• Performing a retrospective analysis of management judgements and assumptions related to significant accounting
estimates reflected in the financial statements of the prior year.
We considered whether there were any significant transactions that are outside the normal course of business, or that
otherwise appear to be unusual due to their nature, timing or size.
The risks and responses to the revenue recognition risks within the trading and shipping function are set out on pages
140-141.
Mitigating controls to address the risk associated with the design deficiencies were identified. These included low-level
analytical reviews, controls over closing balances, period-end analytical review controls and certain automated business
controls. Our testing of these controls concluded they were, in combination, appropriately designed and implemented
and they were operating effectively for the year.
Our substantive testing of journal entries and other adjustments, selected through the use of our data analytics tools,
did not identify any inappropriate items.
We did not identify evidence of overall bias or any significant unusual transactions for which the business rationale (or
the lack thereof) of the transaction suggested that it may have been entered into to engage in fraudulent financial
reporting or to conceal misappropriation of assets.
Management expects the journal control remediation programme to be completed in 2021.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
143
6. Our application of materiality
6.1 Materiality
We define materiality as the magnitude of misstatement in the financial statements that makes it probable that the economic decisions of a reasonably
knowledgeable person would be changed or influenced. We use materiality both in planning the scope of our audit work and in evaluating the results of
our work.
Based on our professional judgement, we determined materiality for the financial statements as a whole as follows:
Materiality
Basis for determining
materiality
Rationale for the
benchmark applied
Parent company financial statements
Materiality has been set at $900 million for the current year
(2019 $1,200 million).
We determined materiality for our audit of the standalone
parent using 1% (2019 1%) of net assets.
The materiality determined for the standalone parent
company financial statements exceeds the group
materiality. This is due to the fact that the net asset balance
of the parent company financial statements exceeds the net
asset balance of the group financial statements. As the
company is nontrading and operates primarily as a holding
company, we believe the net asset position is the most
appropriate benchmark to use.
Where there were balances and transactions within the
parent company accounts that were within the scope of the
audit of the group financial statements, our procedures
were undertaken using the lower materiality level applicable
to the group audit components. It was only for the purposes
of testing balances not relevant to the group audit, such as
intercompany investment balances, that the higher level of
materiality applied in practice.
Group financial statements
Materiality has been set at $600 million for the current year.
In 2019, we used a materiality of $850 million. The decrease
is due to bp’s financial performance in 2020.
Due to the significant losses incurred in 2020 as a
consequence, inter alia, of the COVID-19 pandemic and in
particular the decrease in oil and gas prices, we have
changed our chosen metric from profit before tax in 2019 to
net assets in 2020. We concluded that loss measures are
not appropriate in our determination of materiality.
Materiality was determined to be $600 million, which is
0.73% of net assets.
In 2019, we determined materiality to be $850 million,
which represented 10.3% of profit before taxation, 5% of
underlying replacement cost profit before interest and
taxation and 0.84% of net assets. Recognising the change
in environment and using our professional judgement we
have opted to use a conservative (lower) % of net assets
given the uncertainty as to the level of future results.
We conducted an assessment of which line items are the
most important to investors and analysts by reading analyst
reports and bp's communications to shareholders and
lenders, as well as the communications of peer companies.
We then considered the fact that bp reported a loss during
the year. This resulted in us selecting net assets as the
most appropriate benchmark.
Profit before tax is the benchmark ordinarily considered by
us when auditing listed entities. It provides comparability
against other companies across all sectors, but has
limitations when auditing companies whose earnings are
strongly correlated to commodity prices, which can be
volatile from one period to the next, and therefore may not
be representative of the volume of transactions and the
overall size of the business in the year, or where the impact
of price volatility may result in material impairment charges
or reversals in a particular year. As noted above, the
COVID-19 pandemic and in particular the decrease in oil and
gas prices resulted in significant losses in 2020. We
therefore placed our emphasis on net assets in our
determination of materiality this year.
We further note that the non-GAAP measure underlying
replacement cost profit before interest and tax is one of the
key metrics communicated by management in bp's results
announcements. Although it excludes some of the volatility
arising from changes in crude oil, gas and product prices as
well as 'non-operating items', the significant decrease in oil
and gas prices was such that this measure was also a loss,
and therefore we concluded this was not an appropriate
metric on which to determine materiality this year.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
144
bp Annual Report and Form 20-F 2020
Financial statements
6.2 Performance materiality
We set performance materiality at a level lower than materiality to reduce the probability that, in aggregate, uncorrected and undetected misstatements
exceed the materiality for the financial statements as a whole. Group performance materiality was set at 60% of group materiality for the 2020 audit
(2019 60%) and parent company performance materiality was set at 60% of parent company materiality for the 2020 audit (2019 60%).
Given the significant changes in the business environment due to the COVID-19 pandemic, we maintained a percentage consistent with that of our
2019 audit rather than increasing it to reflect the quality of the control environment and the fact that we are generally able to rely on controls, the
relatively low level of misstatements identified in the current and prior years, as well as the fact that management is generally willing to correct these
misstatements.
6.3 Error reporting threshold
We agreed with the audit committee that we would report to the committee all audit differences in excess of $30 million (2019 $35 million), as well as
differences below that threshold that, in our view, warranted reporting on qualitative grounds. We also report to the audit committee on disclosure
matters that we identified when assessing the overall presentation of the financial statements.
7. An overview of the scope of our audit
7.1 Identification and scoping of components
As a result of the highly disaggregated nature of the group, with operations in over 70 countries through approximately 920 cons units, a significant
portion of our audit planning effort was ensuring that the scope of our work is appropriate in addressing the identified risks of material misstatement.
The factors that we considered when assessing the scope of the bp audit, and the level of work to be performed at the cons units that are in scope for
group reporting purposes, included the following:
• The financial significance of an operating unit (which will typically include multiple cons units) to bp's revenue and loss before tax, or PP&E, including
consideration of the financial significance of specific account balances or transactions.
• The significance of specific risks relating to an operating unit, history of unusual or complex transactions, identification of significant audit issues or
the potential for, or a history of, material misstatements.
• The effectiveness of the control environment and monitoring activities, including entity-level controls.
• The findings, observations and audit differences that we noted as a result of our 2019 audit engagement.
Our audit approach was generally to place reliance on management’s controls over financial reporting.
To ensure we were able to obtain sufficient, appropriate audit evidence for the purposes of our audit of the financial statements, we performed full
scope audit procedures for 173 reporting cons units (2019 179) which were selected based on their size or risk characteristics. The primary reason for
the change in scope is due to certain cons units in the T&S function no longer being used by management to record transactions. Our full-scope audits
are in the UK, US, Azerbaijan, Germany, Canada and Singapore. One of the full-scope cons units includes the investment in Rosneft, a material
associate not controlled by bp.
In addition, component teams performed audit procedures on specified account balances in 62 cons units (2019 55) also covering operations in Angola,
Alaska, Trinidad & Tobago, Mauritania & Senegal, and Australia. The group engagement team performed audit procedures on specified account
balances to component materiality, with certain additional specific procedures performed by component teams, covering an additional 42 cons units
(2019 29).
The remaining cons units are not significant individually and include many small, low risk components and balances. On average, they each represent
0.03% of group revenue (2019 0.03%) and 0.03% of property, plant and equipment (2019 0.03%).
In our assessment of the residual balances not covered by the above procedures, we have considered in particular the risk that there could be a
material misstatement within the large number of geographically dispersed businesses, in particular within the downstream segment. This assessment
included use of our analytic tools to interrogate data, preparation of trend analysis and comparison of business performance to market benchmark
prices. We also tested management's group-wide controls across a range of locations and segments. We concluded that through this additional risk
assessment, we have reduced the audit risk of such a misstatement arising to a sufficiently low level.
Our audit coverage of ‘Property, plant and equipment’ and ‘Sales and other operating revenue’ is materially the same as in the prior year.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
145
Net assets $82,155mGroup materiality $600mComponent materiality range$300m to $180mAudit committee reportingthreshold $30mNet assets $82,155mGroup materiality $600m 7.2 Our consideration of the control environment
Our audit approach was generally to place reliance on management’s relevant controls over all business cycles affecting in scope financial statement
line items. As part of our controls testing, we assessed the design and implementation of controls and tested a sample for operating effectiveness
through a combination of tests of inquiry, observation, inspection and re-performance.
In limited situations where we were not able to take a controls reliance approach due to controls being deficient and there not being sufficient
mitigating or alternative controls we could rely on instead, we adopted a non-controls reliance approach. All control deficiencies which we considered to
be significant, including those in respect of management override (see above) were communicated to the audit committee. All other deficiencies were
communicated to management. For all deficiencies identified we considered the impact and updated our audit plan accordingly.
The group’s financial systems environment is complex, with 113 separate IT systems scoped as being relevant to the audit for the following key
locations (UK, US, Germany, Angola, Azerbaijan and Australia) as well as other minor locations. These systems are all directly or indirectly relevant to
the entity’s financial reporting process.
We planned to rely on the General IT Controls (GITCs) associated with these systems, where the GITCs were appropriately designed and implemented,
and these were operating effectively. To assess the operating effectiveness of GITCs we performed testing on access security, change management,
data centre operations and network operations. We have included our observations on the IT controls in our key audit matter section, (see 'IT controls
relating to financial systems' above).
7.3 Working with other auditors
The group audit team are responsible for the scope and direction of the audit process and provide direct oversight, review, and coordination of our
component audit teams. We interacted regularly with the component Deloitte teams during each stage of the audit and reviewed key working papers.
We maintained continuous and open dialogue with our component teams in addition to holding formal meetings quarterly to ensure that we were fully
aware of their progress and results of their procedures.
Due to the COVID-19 pandemic and the travel restrictions in place during the year, the senior statutory auditor and other group audit partners were
unable to conduct visits to meet with the component teams responsible for the full scope locations, and other key locations including the key Global
Business Services (GBS) accounting locations. As a result of this, we performed alternative virtual procedures which included attending planning
meetings, discussing the audit approach and any issues arising from the component team's work, meetings with local management, and reviewing key
audit working papers on higher and significant-risk areas to drive a consistent and high-quality audit. In addition, a global audit planning meeting was
held virtually for two days in July led by the senior statutory auditor and involving the group audit team, partners and staff from all full scope component
teams, audit teams responsible for testing at key GBS locations, senior management from bp, and the audit committee chairman.
We were provided with direct access to Rosneft's auditor in order to evaluate their audit work on the financial statements of Rosneft, used as the basis
for bp's equity accounting. We held meetings with Rosneft's auditor throughout the year, issued audit instructions to them, reviewed their written
clearance reports responding to these instructions and, through our direct access, were able to exercise appropriate supervision and oversight of their
audit work. We also tested directly bp's procedures and controls over its accounting for the investment in Rosneft.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
146
bp Annual Report and Form 20-F 2020
Property, plant and equipment58%10%7%25%Full audit scopeSpecified account balancesSpecified audit proceduresReview at group levelSales and other operating revenues75%7%18%Full audit scopeSpecified account balancesSpecified audit proceduresReview at group level Financial statements
8. Other information
The directors are responsible for the other information. The other information comprises the information included in the
annual report, other than the financial statements and our auditor’s report thereon.
Our opinion on the financial statements does not cover the other information and, except to the extent otherwise
explicitly stated in our report, we do not express any form of assurance conclusion thereon.
We have nothing to
report in respect of
these matters.
In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so,
consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained
in the audit or otherwise appears to be materially misstated.
If we identify such material inconsistencies or apparent material misstatements, we are required to determine whether
there is a material misstatement in the financial statements or a material misstatement of the other information. If, based
on the work we have performed, we conclude that there is a material misstatement of this other information, we are
required to report that fact.
9. Responsibilities of directors
As explained more fully in the directors’ responsibilities statement, the directors are responsible for the preparation of the financial statements and for
being satisfied that they give a true and fair view, and for such internal control as the directors determine is necessary to enable the preparation of
financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, the directors are responsible for assessing the group’s and the parent company’s ability to continue as a going
concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to
liquidate the group or the parent company or to cease operations, or have no realistic alternative but to do so.
10. Auditor’s responsibilities for the audit of the financial statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether
due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee
that an audit conducted in accordance with ISAs (UK) will always detect a material misstatement when it exists. Misstatements can arise from fraud or
error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users
taken on the basis of these financial statements.
Details of the extent to which the audit was considered capable of detecting irregularities, including fraud and non-compliance with laws and
regulations are set out below.
A further description of our responsibilities for the audit of the financial statements is located on the FRC’s website at: frc.org.uk/
auditorsresponsibilities. This description forms part of our auditor’s report.
11. Extent to which the audit was considered capable of detecting irregularities, including fraud
We identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and then design and perform audit
procedures responsive to those risks, including obtaining audit evidence that is sufficient and appropriate to provide a basis for our opinion.
11.1 Identifying and assessing potential risks related to irregularities
In identifying and assessing risks of material misstatement in respect of irregularities, including fraud and non-compliance with laws and regulations, we
considered the following:
• Our meetings throughout the year with the Group Head of Ethics and Compliance and reviews of bp’s internal ethics and compliance reporting
summaries, including those concerning investigations;
• Enquiries of management, internal audit, and the audit committee, including obtaining and reviewing supporting documentation, concerning the
Group’s policies and procedures relating to:
identifying, evaluating and complying with laws and regulations and whether they were aware of any instances of non-compliance
◦
◦ detecting and responding to the risks of fraud and whether they have knowledge of any actual, suspected or alleged fraud; and
◦
the internal controls established to mitigate risks related to fraud or non-compliance with laws and regulations;
• The group’s remuneration policies, key drivers for remuneration and bonus levels; and
• Discussions among the engagement team regarding how and where fraud might occur in the financial statements and any potential indicators of
fraud. The engagement team includes audit partners and staff who have extensive experience of working with companies in the same sectors as bp
operates, and this experience was relevant to the discussion about where fraud risks may arise. The discussions also involved fraud experts from
Deloitte's forensic accounting function in the Financial Advisory service line, who advised the engagement team of fraud schemes that had arisen in
similar sectors and industries and participated in the initial fraud risk assessment discussions.
In common with all audits under ISAs (UK), we are also required to perform specific procedures to respond to the risk of management override.
We also obtained an understanding of the legal and regulatory frameworks that the group operates in, focusing on provisions of those laws and
regulations that had a direct effect on the determination of material amounts and disclosures in the financial statements. The key laws and regulations
we considered in this context included the UK Companies Act, UK Corporate Governance Code, IFRS as issued by the IASB and adopted by the EU,
FRS 101, US Securities Exchange Act 1934 and relevant SEC regulations, as well as laws and regulations prevailing in each country in which we
identified a full-scope component.
In addition, we considered provisions of other laws and regulations that do not have a direct effect on the financial statements but compliance with
which may be fundamental to the group’s ability to operate or to avoid a material penalty. These included the group’s operating licences, environmental
regulations etc.
11.2 Audit response to risks identified
As a result of performing the above, we did not identify any key audit matters related to the potential risk of fraud or non-compliance with laws and
regulations. We did identify two key audit matters relating to fraud risks, as described above, being the accounting for SCTs and Level 3 instruments
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
147
within T&S, and management override of controls. The key audit matters section of our report explains the matters in more detail and also describes
the specific procedures we performed in response to those key audit matters.
In addition to the above, our procedures to respond to risks identified included the following:
• reviewing the financial statement disclosures and testing to supporting documentation to assess compliance with provisions of relevant laws and
regulations described as having a direct effect on the financial statements;
• enquiring of management, the audit committee and in-house / external legal counsel concerning actual and potential litigation and claims;
• performing analytical procedures to identify any unusual or unexpected relationships that may indicate risks of material misstatement due to fraud;
• reading minutes of meetings of those charged with governance, reviewing internal audit reports and reviewing correspondence with HMRC and IRS;
and
• in addressing the risk of fraud through management override of controls, testing the appropriateness of journal entries and other adjustments;
assessing whether the judgements made in making accounting estimates are indicative of a potential bias; and evaluating the business rationale of
any significant transactions that are unusual or outside the normal course of business.
We also communicated relevant identified laws and regulations and potential fraud risks to all engagement team members including internal specialists
and significant component audit teams, and remained alert to any indications of fraud or non-compliance with laws and regulations throughout the
audit.
Report on other legal and regulatory requirements
12. Opinions on other matters prescribed by the Companies Act 2006
In our opinion the part of the directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006.
In our opinion, based on the work undertaken in the course of the audit:
• The information given in the strategic report and the directors’ report for the financial year for which the financial statements are prepared is
consistent with the financial statements; and
• The strategic report and the directors’ report have been prepared in accordance with applicable legal requirements.
In the light of the knowledge and understanding of the group and the parent company and their environment obtained in the course of the audit, we
have not identified any material misstatements in the strategic report or the directors’ report.
13. Corporate Governance Statement
The Listing Rules require us to review the directors' statement in relation to going concern, longer-term viability and that part of the Corporate
Governance Statement relating to the group’s compliance with the provisions of the UK Corporate Governance Code specified for our review.
Based on the work undertaken as part of our audit, we have concluded that each of the following elements of the Corporate Governance Statement is
materially consistent with the financial statements and our knowledge obtained during the audit:
• the directors’ statement with regards to the appropriateness of adopting the going concern basis of accounting and any material uncertainties
identified set out on page 128;
• the directors’ explanation as to its assessment of the group’s prospects, the period this assessment covers and why the period is appropriate set
out on page 128;
• the directors' statement on fair, balanced and understandable set out on page 127;
• the board’s confirmation that it has carried out a robust assessment of the emerging and principal risks set out on pages 81;
• the section of the annual report that describes the review of effectiveness of risk management and internal control systems set out on page 127;
and
• the section describing the work of the audit committee set out on pages 94-99.
14. Matters on which we are required to report by exception
14.1 Adequacy of explanations received and accounting records
Under the Companies Act 2006 we are required to report to you if, in our opinion:
• We have not received all the information and explanations we require for our audit; or
• Adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not
We have nothing to
report in respect of
these matters.
been received from branches not visited by us; or
• The parent company financial statements are not in agreement with the accounting records and returns.
14.2 Directors’ remuneration
Under the Companies Act 2006 we are also required to report if in our opinion certain disclosures of directors’
remuneration have not been made or the part of the directors’ remuneration report to be audited is not in agreement with
the accounting records and returns.
We have nothing to
report in respect of
these matters.
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
148
bp Annual Report and Form 20-F 2020
Financial statements
15. Other matters
15.1 Auditor tenure
The board appointed Deloitte as the company's auditor with effect from 29 March 2018 to fill the vacancy arising from the resignation of the previous
auditor. On 27 May 2020, shareholders resolved at the annual general meeting to reappoint Deloitte as auditor from the conclusion of the meeting until
the conclusion of the annual general meeting to be held in 2021 and authorized the directors to set the audit fees.
The first accounting period we audited was the 12 month period ended 31 December 2018. The period of total uninterrupted engagement including
previous renewals and reappointments of the firm is 3 years, covering the years ending 31 December 2018 to 31 December 2020.
15.2 Consistency of the audit report with the additional report to the audit committee
Our audit opinion is consistent with the additional report to the audit committee we are required to provide in accordance with ISAs (UK).
16. Use of our report
This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work
has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for
no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the
company’s members as a body, for our audit work, for this report, or for the opinions we have formed.
Douglas King FCA (Senior statutory auditor)
For and on behalf of Deloitte LLP
Statutory Auditor
London, United Kingdom
22 March 2021
This page does not form part of bp's Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
149
Consolidated financial statements of the bp group
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on the financial statements
We have audited the accompanying consolidated group balance sheets of BP p.l.c. and subsidiaries (together the company) as of 31 December 2020
and 2019, the related consolidated group income statements, group statements of comprehensive income, group statements of changes in equity, and
group cash flow statements, for each of the three years in the period ended 31 December 2020, and the related notes (collectively referred to as the
'financial statements'). In our opinion, the financial statements present fairly, in all material respects, the financial position of the company as of
31 December 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended 31 December 2020, in
conformity with International Financial Reporting Standards (IFRS) as adopted by the European Union and IFRS as issued by the International
Accounting Standards Board.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the company's
internal control over financial reporting as of 31 December 2020, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk
Management, Internal Control and Related Financial and Business Reporting relating to internal control over financial reporting and our report dated
22 March 2021 expressed an unqualified opinion on the group's internal control over financial reporting.
Basis for opinion
These financial statements are the responsibility of the group's management. Our responsibility is to express an opinion on the group's financial
statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the
group in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included
performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as
evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or
required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2)
involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion
on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the
critical audit matters or on the accounts or disclosures to which they relate.
1. Property, plant and equipment (PP&E) assets – Impairment of upstream oil and gas – Notes 1, 4 and 12 to the financial statements
Critical Audit Matter Description
The group balance sheet at 31 December 2020 includes PP&E of $115 billion, of which $74 billion is oil and gas properties within the upstream
segment.
Management’s best estimate of oil and gas price assumptions for value–in-use impairment tests were revised downwards during 2020 compared to
the prior year assumptions, as set out in Note 1 on page 161. The downward revisions reflect an expectation that the aftermath of the COVID-19
pandemic will accelerate the pace of transition to a lower carbon economy and energy system. Given the significance of these revisions, management
tested all upstream CGUs for impairment.
Management recorded $12.9 billion of pre-tax upstream CGU impairment charges, in large part due to the oil and gas prices revisions detailed above,
and $0.1 billion of pre-tax upstream CGU impairment reversals. Further information has been provided in Note 1 on page 160, Note 4 on page 179 and
Note 12 on page 189.
Through our audit risk assessment procedures, we have a identified a critical audit matter in respect of PP&E impairment principally due to the
following three key management estimates in management’s determination of the level of impairment charge and/or reversal to record.
• Oil and gas prices - bp’s oil and gas price assumptions have a significant impact on many CGU impairment assessments performed across the
upstream segment, and are inherently uncertain. As noted above, the estimation of future prices is subject to increased uncertainty given climate
change, the global energy transition and the impact of COVID-19. There is a risk that management do not forecast reasonable “best estimate” oil
and gas price forecasts when assessing CGUs for impairment, leading to material misstatements. These price assumptions are highly judgmental
and are pervasive inputs to most upstream impairment tests, such that any misstatements would also aggregate. There is also a risk that
management’s oil and gas price related disclosures are not reasonable.
• Discount rates - Given the long timeframes involved, certain CGU impairment assessments are sensitive to the discount rate applied. Discount
rates should reflect the return required by the market and the risks inherent in the cash flows being discounted. There is a risk that management
do not assume reasonable discount rates, adjusted as applicable for country risks and relevant tax rates, leading to material misstatements.
Determining a reasonable discount rate is highly judgmental and, consistent with price assumptions above, the discount rate assumption is also a
pervasive input across upstream impairment tests, before adjustments for asset specific risks and tax rates, such that any misstatements would
also aggregate.
• Reserves and resources estimates - A key input to certain CGU impairment assessments is the oil and gas production forecast, which is based
on underlying reserves estimates and field specific development assumptions. Certain CGU production forecasts include specific risk adjusted
resource volumes, in addition to proved or probable reserves estimates, that are inherently less certain than reserves; and assumptions related to
these volumes can be particularly judgemental. There is a risk that material misstatements could arise from unreasonable production forecasts for
individually material CGUs and/or from the aggregation of systematic flaws in bp’s reserves and resources estimation policies across the segment.
150
bp Annual Report and Form 20-F 2020
Financial statements
We identified certain individual CGUs with a total carrying value of $32.1 billion which we determined would be most at risk of material impairment
charges or reversals as a result of a plausible change in the key assumptions, particularly oil and gas price and discount rate assumptions.
We also identified CGUs with a further $16.0 billion of combined carrying value which were less sensitive as they would be potentially at risk, in
aggregate, to a material impairment or reversal by a plausible change in some or all of the key assumptions.
Further information regarding these sensitivities is given in Note 1 on page 167.
How the Critical Audit Matter was addressed in the Audit
We tested management’s key internal controls over the estimation of oil and gas prices, discount rates and reserve and resources estimates, as well as
key internal controls over the performance of the impairment assessments where we identified audit risks. In addition, we conducted the following
substantive procedures.
Oil and gas prices
• We independently developed a reasonable range of forecasts based on external data obtained, against which we compared management’s oil and
gas price assumptions in order to challenge whether they are reasonable.
• In developing this range we obtained a variety of reputable and reliable third party forecasts, peer information and other relevant market data.
• In challenging management's price assumptions, we considered the extent to which they and each of the forecast pricing scenarios obtained from
third parties reflect the impact of lower oil and gas demand due to climate change, the energy transition and COVID-19.
• We specifically analysed third party forecasts stated as being, or interpreted by us as being, consistent with achieving the Paris 2°C Goal and
considered whether they presented contradictory audit evidence.
• We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of oil and gas price assumptions to reduced
demand scenarios whether due to climate change or other reasons.
Discount rates
• We independently evaluated bp’s discount rates used in impairment tests with input from Deloitte valuation specialists, against relevant third party
market and peer data.
• We assessed whether specific country risks and tax adjustments were reasonably reflected in bp’s discount rates.
• We challenged management’s disclosures in Notes 1 and 4 including in relation to the sensitivity of discount rate assumptions.
Reserves and resources estimates
With the assistance of Deloitte oil and gas reserves specialists we:
• assessed bp’s reserves and resources estimation methods and policies;
• assessed, guided by our risk assessment, how these policies had been applied to a sample of bp’s reserves and resources estimates which
included those that we judged to represent the greatest risk of material misstatement;
• read a sample of reports provided by management’s external reserves experts and assessed the scope of work and findings of these third parties;
• assessed the competence, capability and objectivity of bp’s internal and external reserve experts; through understanding their relevant
professional qualifications and experience.
• compared the production forecasts used in the impairment tests with management’s approved reserves and resources estimates, those estimates
having been subjected to the controls that we had tested; and
• performed a retrospective assessment to check for indications of estimation bias over time
Other procedures
• We challenged management’s CGU determinations, and considered whether there was any contradictory evidence present.
• We validated that bp’s impairment methodology was acceptable under IFRS and tested the integrity and mechanical accuracy of certain
impairment models based on our risk assessment.
• We challenged other CGU specific valuation input assumptions, including but not limited to material cost and tax forecasts, by comparing forecasts
to approved internal and third party budgets, development plans, independent expectations and historical actuals.
• Where relevant, we assessed management’s historical forecasting accuracy and whether the estimates had been determined and applied on a
consistent basis across the group.
2. Intangible assets – Write-off of Exploration and Appraisal (E&A) assets, included within 'intangible assets' within the Group balance sheet –
Notes 1, 8 and 15 to the financial statements
Critical Audit Matter Description
The group capitalises E&A expenditure on a project-by-project basis in line with IFRS 6 'Exploration for and Evaluation of Mineral Resources'. At 31
December 2020, $4.1 billion of E&A expenditure was carried on the group balance sheet.
E&A activity carries inherent risk and a significant proportion of projects fail, requiring the write-off or impairment of the related capitalised costs when
the relevant criteria in IFRS 6 and bp’s accounting policy are met.
Furthermore, similar to upstream PP&E assets discussed above, E&A assets are also potentially exposed to climate change, the global energy
transition, and COVID-19, in that a greater number of E&A projects may not proceed as a consequence of lower forecast future demand and oil and gas
pricing, lower appetite by management and the board to allocate capital to certain projects, and/or increased objections from stakeholders to the
development of certain projects.
As a result of bp’s revised strategy announced in 2020, including a reduced capital frame, a net-zero carbon ambition and a decision not to explore in
new countries, and reflecting lower oil and gas price assumptions, management identified IFRS 6 impairment indicators at a number of upstream’s
largest E&A assets during the year. This led to management recording $9.9 billion of pre-tax E&A write-offs and impairments during 2020, detailed
further in Notes 1 and 8 on pages 164 and 184.
The determination of when E&A costs should be written off or impaired, or retained on the balance sheet as E&A assets, can be complex and require
significant judgement from management in assessing this. There is a risk that certain capitalised E&A costs are written off or impaired when they
bp Annual Report and Form 20-F 2020
151
should not have been, due to inappropriate and/or inconsistent application of IFRS 6 impairment criteria and bp’s accounting policy, leading to material
misstatements. There is also a risk that E&A costs remain capitalised on the balance sheet which ought to have been written off or impaired, leading to
material misstatements.
We identified a critical audit matter for the individually material E&A write-offs recorded in 2020, specifically the Kaskida and Tigris (Paleogene) licenses
that were the largest part of the $2.5 billion Gulf of Mexico write downs, the Terre de Grace oil sands project that was the largest part of the $2.5 billion
Canada write downs and the three licenses that were the largest part of the $2.1 billion Brazil write-downs. We also identified higher risks in relation
to certain other 2020 E&A write-offs and impairments recorded; and higher risks at certain assets within the $4.4 billion of E&A costs that remain
capitalised under IFRS 6 at 31 December 2020.
How the Critical Audit Matter was addressed in the Audit
We obtained an understanding of the group’s E&A assessment processes and tested management’s key internal controls. This included the key
internal controls operated by management for the key decisions taken as a result of bp’s new strategy, which when taken together with the lower
forecast oil and gas prices, led to a large portion of the material write-offs and impairments recorded during 2020.
We challenged management’s key E&A judgements, with regards to the impairment criteria of IFRS 6 and bp’s accounting policy. We corroborated key
internal and external evidence relevant to significant write-offs and the assets that remained on the balance sheet. This included analysing evidence of
future E&A plans, budgets and capital allocation decisions, assessing management’s key accounting judgement papers, holding discussions to
challenge top level operational and finance management on the key judgements taken and reading meeting minutes, license documentation and
evidence of active dialogue with partners and regulators including negotiations to renew licences or modify key terms, and external press releases.
For E&A assets that were written off or impaired by management in 2020, including in particular those based upon decisions taken in line with
management’s new strategy, we considered whether evidence (and potential contradictory evidence) about activity in the year, future budgeted
expenditure and exploration/appraisal plans, including plans and expectations for licence relinquishment or retention, were consistent with the decisions
taken by management to write-off or impair these assets.
We assessed whether management had consistently applied IFRS 6 and bp’s accounting policy to impairment assessments, taking account of in year
judgements and historical look back considerations, and the relevant facts and circumstances of specific E&A assets.
When considering capital allocation decision making, we considered whether the progression of any projects that remain on the balance sheet would
be inconsistent with elements of bp’s new strategy and in particular its net zero carbon commitments.
3. Accounting for structured commodity transactions (SCTs) within the trading and shipping (T&S) function and the valuation of other Level
3 financial instruments, where fraud risks may arise in revenue recognition (potentially impacting all financial statement accounts, in
particular finance debt) - Notes 1, 20, 22, 29 and 30 to the financial statements
Critical Audit Matter Description
In the normal course of business, T&S enters into a variety of transactions for delivering value across the group’s supply chain. The nature of these
transactions requires significant audit effort to be directed towards challenging management’s valuation estimates or the adopted accounting
treatment.
We have undertaken an analysis of the portfolio composition and revisited our risk assessment throughout the year focussing particularly on the impact
of COVID-19 on the valuation assertion. This process has provided us with a deeper understanding of the impact of market volatility, demand
destruction and the changing structure of the markets in which bp operates.
Accounting for structured commodity transactions:
T&S may also enter into a variety of transactions which we refer to as SCTs. We generally consider a SCT to be an arrangement having one of the
following features:
• Two or more counterparties with non-standard contractual terms;
• Multiple commodity-based transactions; and/or
• Contractual arrangements entered into in contemplation of each other.
SCTs are often long-dated, can have a significant multi-year financial impact, and may require the use of complex valuation models or unobservable
inputs when determining their fair value, in which case they will be classified as level 3 financial instruments under IFRS 13, ‘Fair Value
Measurement’.
Accounting for SCTs is typically complex and involves significant judgment, as these transactions often feature multiple elements that will have a
material impact on the presentation and disclosure of these transactions in the financial statements and on key performance measures, including in
particular the classification of liabilities as finance debt. Accordingly, we have identified the accounting for SCTs as a critical audit matter.
Level 3 financial instruments:
Unlike other financial instruments whose values or inputs are readily observable and therefore more easily independently corroborated, there are certain
transactions for which the valuation is inherently more subjective due to the use of either complex valuation models and/or unobservable inputs. These
instruments are classified as level 3 financial assets or liabilities. This degree of subjectivity also gives rise to a risk of potential fraud through
management incorporating bias in determining fair values. Accordingly, we have identified these as a significant audit risk.
As at 31 December 2020, the group’s total financial assets and liabilities measured at fair value were $12.7 billion and $8.4 billion, of which level 3
derivative financial assets were $6.4 billion and level 3 derivative financial liabilities were $5.3 billion.
How the Critical Audit Matter was addressed in the Audit
Accounting for SCTs
For structured commodity transactions, we:
• Tested controls related to the accounting for complex transactions.
• Developed an understanding of the commercial rationale of the transactions through reading transaction documents and executed agreements,
and discussions with management.
• Performed a detailed accounting analysis for a sample of SCTs involving significant day one profits, deferred working capital arrangements, offtake
arrangements and/or commitments. We confirmed that any day one profits were appropriately deferred.
152
bp Annual Report and Form 20-F 2020
Financial statements
For SCTs which were identified during 2018 and 2019 and that continue through 2020, we have refreshed our assessment in 2020 taking account of
any amendments to the contracts.
To assess the appropriateness of the accounting treatment of SCTs, we embedded technical accounting specialists within the audit team.
Level 3 financial instruments:
To address the complexities associated with auditing the value of level 3 financial instruments, the engagement team included valuation specialists
having significant quantitative and modelling expertise to assist in performing our audit procedures. Our valuation audit procedures included the
following control and substantive procedures:
• We tested the group’s valuation controls including the:
– Model certification control, which is designed to review a model’s theoretical soundness and the appropriateness of its valuation
methodology; and
– Independent price verification control, which is designed to review the appropriateness of valuation inputs that are not observable and are
significant to the financial instrument’s valuation.
• We performed substantive valuation testing procedures at interim and year-end balance sheet date, including:
– Comparing management’s input assumptions against the expected assumptions of other market participants and observable market data;
– Evaluating management’s valuation methodologies against standard valuation practice and analysing whether a consistent framework is
applied across the business period over period; and
– Engaging a Deloitte valuations specialist to challenge models, develop fair value estimates and verify consistency in management’s modelling
and input assumptions throughout the year. Our independent estimates were established using independently sourced inputs (where
available). We evaluated whether the differences between our independent estimates and management’s estimates were within a reasonable
range. In situations where we utilised management’s inputs, these were compared to external data sources to determine whether they were
reasonable.
/s/ Deloitte LLP
London
United Kingdom
22 March 2021
The first accounting period we audited was the 12 month period ended 31 December 2018.
bp Annual Report and Form 20-F 2020
153
Consolidated financial statements of the bp group
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of BP p.l.c. and subsidiaries (the Company) as at 31 December 2020, based on the criteria
established in the UK Financial Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting
relating to internal control over financial reporting (UK FRC Guidance). In our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as at 31 December 2020, based on the criteria established in the UK FRC Guidance.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated
financial statements as at and for the year ended 31 December 2020, of the Company and our report dated 22 March 2021, expressed an unqualified
opinion on those consolidated financial statements.
Basis for opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our
responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary
in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
/s/ Deloitte LLP
London, United Kingdom
22 March 2021
1.
2.
The maintenance and integrity of the BP p.l.c. web site is the responsibility of BP p.l.c.; the work carried out by the auditors does not
involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to
the financial statements since they were initially presented on the web site.
Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in
other jurisdictions.
154
bp Annual Report and Form 20-F 2020
Group income statement
For the year ended 31 December
Sales and other operating revenues
Earnings from joint ventures – after interest and tax
Earnings from associates – after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-retirement benefits
Profit (loss) before taxation
Taxation
Profit (loss) for the year
Attributable to
bp shareholders
Non-controlling interests
Earnings per share
Profit (loss) for the year attributable to bp shareholders
Per ordinary share (cents)
Basic
Diluted
Per ADS (dollars)
Basic
Diluted
Financial statements
Note
2020
2019
6
16
17
7
4
19
5
5
4
8
7
24
9
180,366
(302)
(101)
663
2,874
183,500
132,104
22,494
695
14,889
14,381
10,280
10,397
(21,740)
3,115
33
(24,888)
(4,159)
(20,729)
(20,305)
(424)
(20,729)
$ million
2018
298,756
897
2,856
773
456
303,738
229,878
23,005
1,536
15,457
860
1,445
12,179
19,378
2,528
127
16,723
7,145
9,578
278,397
576
2,681
769
193
282,616
209,672
21,815
1,547
17,780
8,075
964
11,057
11,706
3,489
63
8,154
3,964
4,190
4,026
164
4,190
9,383
195
9,578
11
11
11
11
(100.42)
(100.42)
19.84
19.73
(6.03)
(6.03)
1.19
1.18
46.98
46.67
2.82
2.80
bp Annual Report and Form 20-F 2020
155
Group statement of comprehensive incomea
For the year ended 31 December
Profit (loss) for the year
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Note
2020
(20,729)
2019
4,190
$ million
2018
9,578
Currency translation differences
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss on sale
(1,843)
1,538
(3,771)
of businesses and fixed assets
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement
Costs of hedging marked to market
Costs of hedging reclassified to the income statement
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that may be reclassified
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Income tax relating to items that will not be reclassified
Other comprehensive income
Total comprehensive income
Attributable to
bp shareholders
Non-controlling interests
a See Note 32 for further information.
30
30
30
30
16, 17
9
24
30
9
(353)
78
(37)
42
22
312
66
(1,713)
170
7
(105)
72
(1,641)
(22,370)
(21,983)
(387)
(22,370)
880
(100)
106
(4)
57
82
(70)
2,489
328
(3)
(157)
168
2,657
6,847
6,674
173
6,847
—
(126)
120
(244)
58
417
4
(3,542)
2,317
(37)
(718)
1,562
(1,980)
7,598
7,444
154
7,598
156
bp Annual Report and Form 20-F 2020
Group statement of changes in equitya
Financial statements
Share
capital and
capital
reserves
Treasury
shares
Foreign
currency
translation
reserve
Non-controlling interests
$ million
Fair value
reserves
Profit and
loss
account
bp
shareholders'
equity
Hybrid
bonds
Other
interest
Total equity
At 1 January 2020
Profit for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Cash flow hedges transferred to the balance
sheet, net of tax
Repurchase of ordinary share capital
Share-based payments, net of tax
Share of equity-accounted entities’ changes in
equity, net of tax
Issue of perpetual hybrid bonds
Payments on perpetual hybrid bonds
Tax on issue of perpetual hybrid bonds
Transactions involving non-controlling
interests, net of tax
At 31 December 2020
At 31 December 2018
Adjustment on adoption of IFRS 16, net of tax
At 1 January 2019
Profit for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Cash flow hedges transferred to the balance
sheet, net of tax
Repurchase of ordinary share capital
Share-based payments, net of tax
Share of equity-accounted entities’ changes in
equity, net of tax
Transactions involving non-controlling
interests, net of tax
At 31 December 2019
At 31 December 2017
Adjustment on adoption of IFRS 9, net of tax
At 1 January 2018
Profit for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Cash flow hedges transferred to the balance
sheet, net of tax
Repurchase of ordinary share capital
Share-based payments, net of tax
Share of equity-accounted entities’ changes in
equity, net of tax
Transactions involving non-controlling
interests, net of tax
At 31 December 2018
a See Note 32 for further information.
b See Note 10 for further information.
—
256
—
256
—
—
—
—
2,296 100,708
(680) (20,729)
(1,641)
(643) (22,370)
(6,605)
(238)
37
—
—
—
6
(776)
726
46,525 (14,412)
—
—
—
—
—
—
—
—
(6,495)
—
(2,224)
(2,224)
—
(912) 73,706
— (20,305)
448
98
98 (19,857)
(6,367)
—
98,412
(20,305)
(1,678)
(21,983)
(6,367)
—
(776)
(638)
6
(776)
726
—
—
176
—
—
1,188
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6
—
—
—
—
—
—
1,341
1,341
—
—
1,341
(48)
—
3
(48) 11,909
(89)
—
—
3
— 11,861
(89)
—
3
—
—
—
—
—
(64)
(64)
—
827
763
46,701 (13,224)
(8,719)
(808) 47,300
71,250 12,076
2,242 85,568
46,352
—
46,352
—
—
—
—
(15,767)
—
(15,767)
—
—
—
—
(8,902)
—
(8,902)
—
2,407
2,407
—
—
(987) 78,748
(329)
(987) 78,419
4,026
189
4,215
(6,929)
—
52
52
—
99,444
(329)
99,115
4,026
2,648
6,674
(6,929)
—
—
173
—
—
1,355
—
—
—
23
—
—
—
23
(1,511)
(809)
(1,511)
719
—
—
—
—
—
—
—
—
—
—
(1)
2,104 101,548
(330)
2,103 101,218
4,190
2,657
6,847
(7,142)
164
9
173
(213)
—
—
—
23
(1,511)
719
—
—
—
—
5
5
—
—
5
—
—
—
—
316
316
46,525
(14,412)
(6,495)
(912) 73,706
98,412
46,122
—
46,122
—
—
—
—
—
(16,958)
—
(16,958)
—
—
—
—
—
(5,156)
—
(5,156)
—
(3,746)
(3,746)
—
—
(54)
(743) 75,226
(126)
(797) 75,100
9,383
—
2,023
(216)
(216) 11,406
(6,699)
—
—
26
98,491
(180)
98,311
9,383
(1,939)
7,444
(6,699)
26
—
—
230
1,191
—
—
—
—
(355)
(718)
(355)
703
—
—
—
—
—
—
—
—
—
—
—
—
233
549
2,296 100,708
—
1,913 100,404
(180)
1,913 100,224
9,578
(1,980)
7,598
(6,869)
26
195
(41)
154
(170)
—
—
—
(355)
703
—
—
—
—
14
14
—
—
14
—
—
—
—
—
—
46,352
(15,767)
(8,902)
(987) 78,748
99,444
—
—
207
207
2,104 101,548
bp Annual Report and Form 20-F 2020
157
Group balance sheet
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Fixed assets
Loans
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits
Total liabilities
Net assets
Equity
bp shareholders’ equity
Non-controlling interests
Total equity
Helge Lund Chairman
Bernard Looney Chief executive officer
22 March 2021
158
bp Annual Report and Form 20-F 2020
Note
2020
12
14
15
16
17
18
20
30
9
24
19
20
30
18
25
2
22
30
28
26
23
2
22
30
28
26
9
23
24
114,836
12,480
6,093
8,362
18,975
2,746
163,492
840
4,351
9,755
533
7,744
7,957
194,672
458
16,873
17,948
2,992
1,269
672
333
31,111
71,656
1,326
72,982
267,654
36,014
2,998
4,650
1,933
9,359
1,038
3,761
59,753
46
59,799
12,112
5,404
852
7,329
63,305
6,831
17,200
9,254
122,287
182,086
85,568
$ million
2019
132,642
11,868
15,539
9,991
20,334
1,276
191,650
630
2,147
6,314
781
4,560
7,053
213,135
339
20,880
24,442
4,153
857
1,282
169
22,472
74,594
7,465
82,059
295,194
46,829
3,261
5,066
2,067
10,487
2,039
2,453
72,202
1,393
73,595
12,626
5,537
996
7,655
57,237
9,750
18,498
8,592
120,891
194,486
100,708
32
32
32
71,250
14,318
85,568
98,412
2,296
100,708
Group cash flow statement
For the year ended 31 December
Operating activities
Profit (loss) before taxation
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Exploration expenditure written off
Depreciation, depletion and amortization
Impairment and (gain) loss on sale of businesses and fixed assets
Earnings from joint ventures and associates
Dividends received from joint ventures and associates
Interest receivable
Interest received
Finance costs
Interest paid
Net finance expense relating to pensions and other post-retirement benefits
Share-based payments
Net operating charge for pensions and other post-retirement benefits, less contributions
and benefit payments for unfunded plans
Net charge for provisions, less payments
(Increase) decrease in inventories
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Income taxes paid
Net cash provided by operating activities
Investing activities
Expenditure on property, plant and equipment, intangible and other assets
Acquisitions, net of cash acquired
Investment in joint ventures
Investment in associates
Total cash capital expenditure
Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposed
Proceeds from loan repayments
Net cash used in investing activities
Financing activities
Repurchase of shares
Lease liability payments
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
Issue of perpetual hybrid bonds
Payments on perpetual hybrid bonds
Payments relating to transactions involving non-controlling interests (other)
Receipts relating to transactions involving non-controlling interests (other)
Dividends paid
bp shareholders
Non-controlling interests
Net cash provided by (used in) financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Financial statements
Note
2020
2019
$ million
2018
(24,888)
8,154
16,723
8
5
4
7
24
24
3
4
4
10
9,920
14,889
11,507
403
1,442
(258)
74
3,115
(2,728)
33
723
(282)
735
3,963
4,230
(8,278)
(2,438)
12,162
(12,306)
(44)
(567)
(1,138)
(14,055)
491
4,989
717
(7,858)
(776)
(2,442)
14,736
(12,179)
(1,234)
11,861
(89)
(8)
665
(6,340)
(238)
3,956
379
8,639
22,472
31,111
631
17,780
7,882
(3,257)
1,962
(441)
416
3,489
(2,870)
63
730
(238)
(176)
(3,406)
(2,335)
2,823
(5,437)
25,770
(15,418)
(3,562)
(137)
(304)
(19,421)
500
1,701
246
(16,974)
(1,511)
(2,372)
8,597
(7,118)
180
—
—
—
566
(6,946)
(213)
(8,817)
25
4
22,468
22,472
1,085
15,457
404
(3,753)
1,535
(468)
348
2,528
(1,928)
127
690
(386)
986
672
(2,858)
(2,577)
(5,712)
22,873
(16,707)
(6,986)
(382)
(1,013)
(25,088)
940
1,911
666
(21,571)
(355)
(35)
9,038
(7,175)
1,317
—
—
—
—
(6,699)
(170)
(4,079)
(330)
(3,107)
25,575
22,468
bp Annual Report and Form 20-F 2020
159
Notes on financial statements
1. Significant accounting policies, judgements, estimates and assumptions
Authorization of financial statements and statement of compliance with International Financial Reporting Standards
The consolidated financial statements of BP p.l.c and its subsidiaries (collectively referred to as bp or the group) for the year ended 31 December 2020
were approved and signed by the chief executive officer and chairman on 22 March 2021 having been duly authorized to do so by the board of
directors. BP p.l.c. is a public limited company incorporated and domiciled in England and Wales. The consolidated financial statements have been
prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS
adopted pursuant to Regulation (EC) No 1606/2002 as it applies in the European Union (EU) and in accordance with the provisions of the UK Companies
Act 2006 as applicable to companies reporting under international accounting standards. IFRS as adopted by the EU differs in certain respects from
IFRS as issued by the IASB. The differences have no impact on the group’s consolidated financial statements for the years presented. As a result of the
UK's withdrawal from the EU, with effect for periods starting subsequent to the year ended 31 December 2020, the consolidated financial statements
will also be prepared in accordance with UK-adopted international accounting standards. There were no differences between IFRS as adopted by the
EU and UK-adopted international accounting standards as at 1 January 2021. The UK’s withdrawal from the EU has not had and is not expected to have
a significant impact on the consolidated financial statements. The significant accounting policies and accounting judgements, estimates and
assumptions of the group are set out below.
Basis of preparation
The consolidated financial statements have been prepared on a going concern basis and in accordance with IFRS and IFRS Interpretations Committee
(IFRIC) interpretations issued and effective for the year ended 31 December 2020. The accounting policies that follow have been consistently applied to
all years presented, except where otherwise indicated.
The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where
otherwise indicated.
Significant accounting policies: use of judgements, estimates and assumptions
Inherent in the application of many of the accounting policies used in preparing the consolidated financial statements is the need for bp management to
make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and
liabilities, and the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The
accounting judgements and estimates that have a significant impact on the results of the group are set out in boxed text below, and should be read in
conjunction with the information provided in the Notes on financial statements. The areas requiring the most significant judgement and estimation in
the preparation of the consolidated financial statements are: accounting for the investment in Rosneft; exploration and appraisal intangible assets; the
recoverability of asset carrying values, including the estimation of reserves; supplier financing arrangements; derivative financial instruments;
provisions and contingencies; and pensions and other post-retirement benefits. Judgements and estimates, not all of which are significant, made in
assessing the impact of the COVID-19 pandemic, and climate change and the transition to a lower carbon economy on the consolidated financial
statements are also set out in boxed text below. Where an estimate has a significant risk of resulting in a material adjustment to the carrying amounts
of assets and liabilities within the next financial year this is specifically noted within the boxed text.
Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy
Climate change and the transition to a lower carbon economy were considered in preparing the consolidated financial statements. These may have
significant impacts on the currently reported amounts of the group’s assets and liabilities discussed below and on similar assets and liabilities that
may be recognized in the future.
Impairment of property, plant and equipment, and goodwill
The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount
of property, plant and equipment, and goodwill in the oil and gas industry. Management’s best estimate of oil and natural gas price assumptions for
value-in-use impairment testing were revised downwards during 2020 and the period covered extended to 2050. The revised assumptions sit within
the range of external forecasts considered by management and are broadly in line with a range of transition paths consistent with the goals of the
Paris climate change agreement. See significant judgements and estimates: recoverability of asset carrying values for further information including
sensitivity analysis in relation to reasonably possible changes in the price assumptions.
Impairments were recognized during 2020 on certain Upstream oil and gas properties as a result of the lower price assumptions. See note 4 for
further information.
No material impairments were recognized on Downstream assets. Though the energy transition may impact demand for certain refined products in
the future, management anticipates sufficiently robust demand for the remainder of each refinery’s useful life.
Headroom on goodwill balances was reduced, however the recoverable amount exceeds the carrying amount. See note 14 for further information
including sensitivity analysis on the assumptions used to test goodwill for impairment.
Management will continue to review price assumptions as the energy transition progresses and this may result in impairment charges or reversals in
the future.
Exploration and appraisal intangible assets
The energy transition may affect the future development or viability of exploration prospects. The lower price assumptions and work to develop bp’s
new strategy resulted in a review of the recoverability of exploration and appraisal intangible assets during 2020. Certain intangible assets were
subsequently written-off. See significant judgement: exploration and appraisal intangible assets and note 8 for further information.
The revised long-term price assumptions for investment appraisal (see page 28) help create a framework that seeks to help ensure that currently
unsanctioned future capital expenditure on property plant and equipment, and exploration and appraisal intangibles, is aligned with bp’s new strategy.
Property, plant and equipment – depreciation and expected useful lives
The energy transition may curtail the expected useful lives of oil and gas industry assets thereby accelerating depreciation charges. However, the
significant majority of bp’s existing Upstream oil and natural gas properties are likely to be fully depreciated within the next 10 years and, as outlined
in bp's new strategy, oil and natural gas production will remain an important part of bp’s business activities over that period. Similarly, for Downstream
refineries, demand for refined products is expected to remain strong over the remaining useful life of existing assets.
160
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Therefore, management does not expect the useful lives of bp’s reported property, plant and equipment to change and do not consider this to be a
significant accounting judgement or estimate. Significant capital expenditure is still required for ongoing projects and therefore the useful lives of
future capital expenditure may, however, be different. See significant accounting policy: property, plant and equipment for more information.
Provisions: decommissioning
The energy transition may bring forward the decommissioning of oil and gas industry assets thereby increasing the present value of associated
decommissioning provisions. The majority of bp’s Upstream oil and gas properties are expected to start decommissioning within the next two
decades and management does not expect any reasonable change in the expected timeframe to have a material effect on the Upstream
decommissioning provisions, assuming cash flows remain unchanged. Decommissioning cost estimates are based on the known regulatory and
external environment. These cost estimates may change in the future, including as a result of the transition to a lower carbon economy. For
Downstream refineries, decommissioning provisions are generally not recognized as the associated obligations have indeterminate settlement dates,
typically driven by the cessation of manufacturing. Management will continue to review facts and circumstances to assess if decommissioning
provisions need to be recognized. See significant judgements and estimates: provisions for further information.
Judgements and estimates made in assessing the impact of the COVID-19 pandemic and the economic environment
In preparing the consolidated financial statements, the following areas involving judgement and estimates were identified as most relevant with
regards to the impact of the COVID-19 pandemic and current economic environment.
Going concern
Forecast liquidity has been assessed under a number of stressed scenarios, including a significant decline in oil prices over the 12-month period.
Reverse stress tests performed indicated that the group will continue to operate as a going concern for at least 12 months from the date of approval
of the consolidated financial statements even if the Brent price fell to zero. No material uncertainties over going concern or significant judgements or
estimates in the assessment were identified. See also Note 29 Financial instruments and financial risk factors – Liquidity risk for further information.
Discount rate assumptions
The discount rates used for impairment testing and provisions were reassessed during the year in light of changing economic and geopolitical
outlooks. The impact was determined not to be significant and the post-tax impairment discount rate and nominal provisions discount rate were
unchanged from 2019. Pre-tax impairment discount rates and post-tax premiums for certain higher-risk countries were changed but this did not have a
material impact. See significant judgements and estimates: recoverability of asset carrying values and provisions for further information.
Oil and natural gas price assumptions
The price assumptions used in value-in-use impairment testing were revised downwards during the year, in part due to lower demand for oil and
natural gas. Material impairment charges and exploration write-offs were recognized in the Upstream segment as a consequence of these price
assumption changes. See significant judgements and estimates: recoverability of asset carrying values and exploration and appraisal intangible assets
for further information.
Demand constraints for refined products during the year did not result in any material impairment charges on Downstream refinery assets.
Pensions and other post-retirement benefits
The volatility in the financial markets during 2020 impacted the assumptions used for determining the fair value of plan assets and the present value
of defined benefit obligations in the group’s defined benefit pension plans. See significant estimate: pensions and other post-retirement benefits and
note 24 for further information.
Impairment of financial assets measured at amortized cost
The current economic environment and future credit risk outlook were considered in updating the estimate of expected credit loss allowances on
financial assets measured at amortized cost. Whilst credit risk increased relative to 31 December 2019, there was also a significant reduction in the
group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized as at 31 December 2020 did not
significantly increase. Management does not consider the calculation of expected credit loss allowances to be a significant accounting estimate. See
note 21 and 29 for further information.
Income taxes
The carrying amounts of the group’s deferred tax assets were reviewed and updated to the extent that there are changes in the probability of
sufficient taxable profits being available to utilize the reported deferred tax assets. Management does not consider the measurement of deferred tax
assets to be a significant accounting estimate. See significant accounting policy: income taxes and Note 9 for further information.
Basis of consolidation
The consolidated group financial statements consolidate the financial statements of BP p.l.c. and its subsidiaries drawn up to 31 December each year.
Subsidiaries are consolidated from the date of their acquisition, being the date on which the group obtains control, including when control is obtained
via potential voting rights, and continue to be consolidated until the date that control ceases. The financial statements of subsidiaries are prepared for
the same reporting year as the parent company, using consistent accounting policies. Intra-group balances and transactions, including unrealized profits
arising from intra-group transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence of an impairment
of the asset transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders.
Included within non-controlling interests are perpetual subordinated hybrid bonds issued by a subsidiary and for which the group has the unconditional
right to avoid transferring cash or another financial asset to the bondholders. Profit or loss attributable to bp shareholders is adjusted to reflect the
coupon related to these hybrid bonds whether or not such distribution has been deferred.
Interests in other entities
Business combinations and goodwill
Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are recognized at their
fair values at the acquisition date.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling interest
and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and liabilities
assumed at the acquisition date. The amount recognized for any non-controlling interest is measured at the present ownership's proportionate share in
bp Annual Report and Form 20-F 2020
161
1. Significant accounting policies, judgements, estimates and assumptions – continued
the recognized amounts of the acquiree’s identifiable net assets. At the acquisition date, any goodwill acquired is allocated to each of the cash-
generating units, or groups of cash-generating units, expected to benefit from the combination’s synergies. Following initial recognition, goodwill is
measured at cost less any accumulated impairment losses. Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous
carrying amount under UK generally accepted accounting practice, less subsequent impairments.
Goodwill may arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the net fair
value of the identifiable assets and liabilities. Any such goodwill is recorded within the corresponding investment in joint ventures and associates.
Goodwill may also arise upon acquisition of interests in joint operations that meet the definition of a business. The amount of goodwill separately
recognized is the excess of the consideration transferred over the group's share of the net fair value of the identifiable assets and liabilities.
Interests in joint arrangements
The results, assets and liabilities of joint ventures are incorporated in these consolidated financial statements using the equity method of accounting as
described below.
Certain of the group’s activities, particularly in the Upstream segment, are conducted through joint operations. bp recognizes, on a line-by-line basis in
the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations incurred jointly with the other partners,
along with the group’s income from the sale of its share of the output and any liabilities and expenses that the group has incurred in relation to the joint
operation.
Interests in associates
The results, assets and liabilities of associates are incorporated in these consolidated financial statements using the equity method of accounting as
described below.
Significant judgement: investment in Rosneft
Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For bp, the judgement
that the group has significant influence over Rosneft Oil Company (Rosneft), a Russian oil and gas company is significant. As a consequence of this
judgement, bp uses the equity method of accounting for its investment and bp's share of Rosneft's oil and natural gas reserves is included in the
group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the investment would be accounted for
as an investment in an equity instrument measured at fair value as described under 'Financial assets' below and no share of Rosneft's oil and natural
gas reserves would be reported.
Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not control or
joint control of those policies. Significant influence is presumed when an entity owns 20% or more of the voting power of the investee. Significant
influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee.
bp owns 19.75% of the voting shares of Rosneft. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the
Russian government. At 31 December 2020, Rosneftegaz held 40.4% (2019 50% plus one share) of the voting shares of Rosneft . IFRS identifies
several indicators that may provide evidence of significant influence, including representation on the board of directors of the investee and
participation in policy-making processes. bp’s group chief executive, Bernard Looney, was approved as a member of the board of directors of Rosneft
in June 2020 as one of bp’s two nominated directors. bp’s other nominated director, Bob Dudley, has been a member of the Rosneft board since
2013. He is also chairman of the Rosneft board’s Strategic and Sustainable Development Committee. bp also holds the voting rights at general
meetings of shareholders conferred by its 19.75% stake in Rosneft. Transactions by Rosneft in its own shares during the year have increased bp’s
economic interest in Rosneft to 22.03% (2019 19.75%). bp's management considers, therefore, that the group has significant influence over Rosneft,
as defined by IFRS.
The equity method of accounting
Under the equity method, an investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of the
entity, less distributions received and less any impairment in value of the investment. Loans advanced to equity-accounted entities that have the
characteristics of equity financing are also included in the investment on the group balance sheet. The group income statement reflects the group’s
share of the results after tax of the equity-accounted entity, adjusted to account for depreciation, amortization and any impairment of the equity-
accounted entity’s assets based on their fair values at the date of acquisition. The group statement of comprehensive income includes the group’s
share of the equity-accounted entity’s other comprehensive income. The group’s share of amounts recognized directly in equity by an equity-accounted
entity is recognized in the group’s statement of changes in equity.
Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise in the
accounting policies used by the equity-accounted entity and those used by bp, adjustments are made to those financial statements to bring the
accounting policies used into line with those of the group.
Unrealized gains on transactions, apart from those that meet the definition of a derivative, between the group and its equity-accounted entities are
eliminated to the extent of the group’s interest in the equity-accounted entity.
The group assesses investments in equity-accounted entities for impairment whenever there is objective evidence that the investment is impaired. If
any such objective evidence of impairment exists, the carrying amount of the investment is compared with its recoverable amount, being the higher of
its fair value less costs of disposal and value in use. If the carrying amount exceeds the recoverable amount, the investment is written down to its
recoverable amount.
Segmental reporting
The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief
executive, bp’s chief operating decision maker, in deciding how to allocate resources and in assessing performance.
The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires
that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker.
For bp, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of inventories sold in the
period and is arrived at by excluding inventory holding gains and losses from profit before interest and tax. Replacement cost profit for the group is not
a recognized measure under IFRS. For further information see Note 5.
For information on changes to bp's segmental reporting see ‘Change in segmentation from 1 January 2021’ below.
162
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Foreign currency translation
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of those
entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into
the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the income statement,
unless hedge accounting is applied. Non-monetary items, other than those measured at fair value, are not retranslated subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures, associates, and
related goodwill, are translated into US dollars at the spot exchange rate on the balance sheet date. The results and cash flows of non-US dollar
functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. In the consolidated
financial statements, exchange adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional
currency subsidiaries, joint ventures and associates are translated into US dollars are recognized in a separate component of equity and reported in
other comprehensive income. Exchange gains and losses arising on long-term intra-group foreign currency borrowings used to finance the group’s non-
US dollar investments are also reported in other comprehensive income if the borrowings form part of the net investment in the subsidiary, joint
venture or associate. On disposal or for certain partial disposals of a non-US dollar functional currency subsidiary, joint venture or associate, the related
accumulated exchange gains and losses recognized in equity are reclassified from equity to the income statement.
Non-current assets held for sale
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Significant non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction
rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available
for immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be
committed to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held
for sale, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made or that the
plan will be withdrawn.
Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale.
Intangible assets
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software,
patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses.
Intangible assets are carried initially at cost unless acquired as part of a business combination. Any such asset is measured at fair value at the date of
the business combination and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis over
their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement and
economic useful life, and can range from three to fifteen years. Computer software costs generally have a useful life of three to five years.
The expected useful lives of assets and the amortization method are reviewed on an annual basis and, if necessary, changes in useful lives or the
amortization method are accounted for prospectively.
Oil and natural gas exploration, appraisal and development expenditure
Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of
accounting as described below.
Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm
that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still
under way or planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of
technical and commercial considerations, and sufficient progress is being made on establishing development plans and timing. If no future activity is
planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight-
line basis over the estimated period of exploration. Upon internal approval for development and recognition of proved or sanctioned probable reserves
of oil and natural gas, the relevant expenditure is transferred to property, plant and equipment.
Exploration and appraisal expenditure
Geological and geophysical exploration costs are recognized as an expense as incurred. Costs directly associated with an exploration well are initially
capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee
remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found,
the exploration well costs are written off. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial
development, the costs continue to be carried as an asset. If it is determined that development will not occur, that is, the efforts are not successful,
then the costs are expensed.
Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the
initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an intangible
asset. Upon internal approval for development and recognition of proved or sanctioned probable reserves, the relevant expenditure is transferred to
property, plant and equipment. If development is not approved and no further activity is expected to occur, then the costs are expensed.
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within one
year of well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover potentially
economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. an offshore platform or a pipeline) would be required
before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further
exploration or appraisal work in the area, remain capitalized on the balance sheet as long as such work is under way or firmly planned.
bp Annual Report and Form 20-F 2020
163
1. Significant accounting policies, judgements, estimates and assumptions – continued
Development expenditure
Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development
wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated from
the commencement of production as described below in the accounting policy for property, plant and equipment.
Significant judgement: exploration and appraisal intangible assets
Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-type
stratigraphic test wells on the balance sheet. This includes costs relating to exploration licences or leasehold property acquisitions. It is not unusual to
have such costs remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil
and natural gas field is performed or while the optimum development plans and timing are established.The costs are carried based on the current
regulatory and political environment or any known changes to that environment. All such carried costs are subject to regular technical, commercial and
management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this
is no longer the case, the costs are immediately expensed.
As a result of the revised price assumptions detailed in Significant judgements and estimates: recoverability of asset carrying values below and a
review of bp’s long-term strategic plan, management reviewed bp’s exploration prospects and the carrying value of the associated intangible assets.
The outcome of the review resulted in revised judgements over management's expectations to extract value from certain prospects, thereby leading
to material write-offs of the associated exploration and appraisal intangible assets in 2020.
The carrying amount of capitalized costs and further information on the write-offs are included in Note 8.
Property, plant and equipment
Property, plant and equipment owned by the group is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost
of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and condition
necessary for it to be capable of operating in the manner intended by management, the initial estimate of any decommissioning obligation, if applicable,
and, for assets that necessarily take a substantial period of time to get ready for their intended use, directly attributable general or specific finance
costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs.
Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item
will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with
major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance
programmes, and all other maintenance costs are expensed as incurred.
Oil and natural gas properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is
amortized over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved
reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together with estimated
future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities.
Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the income statement as
depreciation, depletion and amortization is contained in Note 12 and Note 5 respectively.
Estimates of oil and natural gas reserves determined in accordance with US Securities and Exchange Commission (SEC) regulations, including the
application of prices using 12-month historical price data in assessing the commerciality of technical volumes, are typically used to calculate
depreciation, depletion and amortization charges for the group’s oil and gas properties. Therefore, where this approach is adopted, charges are not
dependent on management forecasts of future oil and gas prices.
However, for certain oil and natural gas assets, the use of reserves determined in accordance with SEC regulations would result in a charge that is not
reflective of the pattern in which the future economic benefits are expected to be consumed. In these limited instances other approaches are applied to
determine the reserves base used to calculate depreciation, depletion and amortization, including the use of management’s best estimate of price
assumptions as disclosed in Significant judgements and estimates: recoverability of asset carrying values, to determine the commerciality of technical
proved reserves.
The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the
expected future production.
The estimation of oil and natural gas reserves and bp’s process to manage reserves bookings is described in Supplementary information on oil and
natural gas on page 231, which is unaudited. Details on bp’s proved reserves and production compliance and governance processes are provided on
page 312. The 2020 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in
Supplementary information on oil and natural gas (unaudited) on page 231.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s other
property, plant and equipment are as follows:
Land improvements
Buildings
Refineries
Petrochemicals plants
Pipelines
Service stations
Office equipment
Fixtures and fittings
15 to 25 years
20 to 50 years
20 to 30 years
20 to 30 years
10 to 50 years
15 years
3 to 10 years
5 to 15 years
The expected useful lives and depreciation method of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in
useful lives or the depreciation method are accounted for prospectively.An item of property, plant and equipment is derecognized upon disposal or
when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset
(calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the income statement in the period
in which the item is derecognized.
164
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Impairment of property, plant and equipment, intangible assets, and goodwill
The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, plans to dispose
rather than retain assets, changes in the group’s assumptions about commodity prices, low plant utilization, evidence of physical damage or, for oil and
gas assets, significant downward revisions of estimated reserves or increases in estimated future development expenditure or decommissioning costs.
If any such indication of impairment exists, the group makes an estimate of the asset’s or CGU’s recoverable amount. Individual assets are grouped
into CGUs for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash
flows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. If it is probable
that the value of the CGU will be primarily recovered through a disposal transaction, the expected disposal proceeds are considered in determining the
recoverable amount. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its
recoverable amount.
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the
determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined
products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. Carbon taxes and costs of emissions allowances are included in
estimates of future cash flows, where applicable, based on the regulatory environment in each jurisdiction in which the group operates. As an initial
step in the preparation of these plans, various assumptions regarding market conditions, such as oil prices, natural gas prices, refining margins, refined
product margins and cost inflation rates are set by senior management. These assumptions take account of existing prices, global supply-demand
equilibrium for oil and natural gas, other macroeconomic factors and historical trends and variability. In assessing value in use, the estimated future cash
flows are adjusted for the risks specific to the asset group that are not reflected in the discount rate and are discounted to their present value typically
using a pre-tax discount rate that reflects current market assessments of the time value of money.
Fair value less costs of disposal is the price that would be received to sell the asset in an orderly transaction between market participants and does not
reflect the effects of factors that may be specific to the group and not applicable to entities in general. In limited circumstances where recent market
transactions are not available for reference, discounted cash flow techniques are applied. Where discounted cash flow analyses are used to calculate
fair value less costs of disposal, estimates are made about the assumptions market participants would use when pricing the asset, CGU or group of
CGUs containing goodwill and the test is performed on a post-tax basis.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist
or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if
there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is
the case, the carrying amount of the asset is increased to the lower of its recoverable amount and the carrying amount that would have been
determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Impairment reversals are recognized in profit or
loss. After a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any residual value, on a
systematic basis over its remaining useful life.
Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the group of
CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the group of CGUs
to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of CGUs is less than the
carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not reversed in a subsequent
period.
bp Annual Report and Form 20-F 2020
165
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant judgements and estimates: recoverability of asset carrying values
Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management estimates on
highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, capital expenditure, production profiles,
reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for crude oil,
natural gas and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the appropriate grouping
of CGUs for impairment testing purposes. For example, individual oil and gas properties may form separate CGUs whilst certain oil and gas properties
with shared infrastructure may be grouped together to form a single CGU. Alternative groupings of assets or CGUs may result in a different outcome
from impairment testing. See Note 14 for details on how these groupings have been determined in relation to the impairment testing of goodwill.
As described above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs
of disposal may be determined based on expected sales proceeds or similar recent market transaction data.
Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts of assets
are shown in Note 12, Note 14 and Note 15.
The estimates for assumptions made in impairment tests in 2020 relating to discount rates and oil and gas properties are discussed below. Changes
in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in a material change
to the carrying values of the group's assets within the next financial year.
Discount rates
For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted
using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and
incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use
the post-tax discount rate.
The discount rates applied in impairment tests are reassessed each year and in 2020, the post-tax discount rate was 6% (2019 6%). Where the CGU
is located in a country that was judged to be higher risk an additional premium of 1% to 3% was reflected in the post-tax discount rate (2019 1% to
4%). The judgement of classifying a country as higher risk and the applicable premium takes into account various economic and geopolitical factors.
The pre-tax discount rate typically ranged from 7% to 15% (2019 7% to 13%) depending on the risk premium and applicable tax rate in the geographic
location of the CGU.
Oil and natural gas properties
For Upstream oil and natural gas properties, expected future cash flows are estimated using management’s best estimate of future oil and natural gas
prices, and production and reserves volumes. The estimated future level of production in all impairment tests is based on assumptions about future
commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors.
In 2020, the group identified Upstream oil and gas properties with carrying amounts totalling $45,027 million (2019 $25,092 million) where the
headroom, based on the most recent impairment test performed in the year on those assets, was less than or equal to 20% of the carrying value. A
change in the discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of
one or more of these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that
period. Management considers that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas
prices and/or production could result in a material change in their carrying amounts within the next financial year,see Sensitivity analyses, below.
The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development
expenditure above.
Oil and natural gas prices
The price assumptions used for value in use impairment testing are based on those used for investment appraisal. The investment appraisal price
assumptions are recommended by the senior vice president economic & energy insights after considering a range of external prices, and supply and
demand forecasts under various energy transition scenarios. They are reviewed and approved by management. As a result of the current uncertainty
over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals
of the Paris climate change agreement, the forecasts and scenarios considered include those where those goals are met as well as those where they
are not met.
bp sees the prospect of an enduring impact on the global economy as a result of the COVID-19 pandemic, with the potential for weaker demand for
energy for a sustained period. bp’s management also expects that the aftermath of the pandemic will accelerate the pace of transition to a lower
carbon economy and energy system as countries seek to ‘build back better’ so that their economies will be more resilient in the future. As a result of
all the above, bp revised its price assumptions for value-in-use impairment testing, lowering them compared to those used in 2019 and extending the
period covered to 2050. These price assumptions are derived from the central case investment appraisal assumptions (see page 28). A summary of
the group’s revised price assumptions, in real 2020 terms, is provided below. The assumptions represent management’s best estimate of future
prices, which sit within the range of external forecasts considered as appropriate for the purpose. They are considered by bp to be broadly in line with
a range of transition paths consistent with the Paris climate goals. However, they do not correspond to any specific Paris-consistent scenario. An
inflation rate of 2% (2019 2%) is applied to determine the price assumptions in nominal terms.
Brent oil ($/bbl)
Henry Hub gas ($/mmBtu)
2021
50
3.00
2025
50
3.00
2030
60
3.00
2040
60
3.00
2050
50
2.75
166
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Material impairment charges were recognized in 2020 following the downward revision of the price assumptions. See Note 4 for further information.
The long-term price assumptions used to determine recoverable amount based on value-in-use impairments tests in 2019 were $70 per barrel for
Brent and $4 per mmBtu for Henry Hub gas, both in 2015 prices. These long-term prices were applied from 2025 and 2032 respectively inflated for
the remaining life of the asset.
The price assumptions used in 2019 over the periods to 2025 and 2032 were set such that there was a linear progression from our best estimate of
2020 prices to the long-term assumptions.
The majority of bp’s reserves and resources that support the carrying value of the group’s existing oil and gas properties are expected to be produced
over the next 10 years.
Oil prices fell 35% in 2020 from 2019 due to trade tensions, a macroeconomic downturn and a slowdown in oil demand, reflecting the impact of the
COVID-19 pandemic. OPEC+ production restraint, unplanned outages, and sanctions on Venezuela and Iran kept prices from falling further. bp's long-
term assumption for oil prices is higher than the 2020 price average, based on the judgement that current price levels would not encourage sufficient
investment to meet global oil demand sustainably in the longer term, especially given the financial requirements of key low-cost oil producing
economies.
US gas prices dropped by around 20% in 2020 compared to 2019. Henry Hub gas prices were already low in early 2020 due to mild weather. The drop
in demand from the second quarter onward as a result of the COVID-19 pandemic as well as significant US LNG shut-ins contributed to prices
remaining below $2/mmBtu during the second and third quarters, despite a record consumption in the power sector and the drop in natural gas
production. Prices recovered in the fourth quarter due to the seasonal gas demand increase and the strong recovery in US LNG exports. bp's long-
term price assumption for US gas reflects the fact that over the coming decades US gas production increases with an increasing proportion of
production being used as feedstock to supply expanding LNG exports, while in the longer-term falling gas consumption and declining demand for
global LNG exports leads to increasing competitive pressure on US gas production.
Oil and natural gas reserves
In addition to oil and natural gas prices, significant technical and commercial assessments are required to determine the group’s estimated oil and
natural gas reserves. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering data,
reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of the group’s estimates of its
oil and natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial
assessments based on conventional industry practice and regulatory requirements.
Reserves assumptions for value-in-use tests reflect the reserves and resources that management currently intend to develop. The recoverable
amount of oil and gas properties is determined using a combination of inputs including reserves, resources and production volumes. Risk factors may
be applied to reserves and resources which do not meet the criteria to be treated as proved or probable.
Sensitivity analyses
A change in revenue from Upstream oil and gas properties can arise either due to changes in oil and natural gas prices, changes in oil and natural gas
production, or a combination of the two.
Management tested the impact of a change in revenue cash flows in value-in-use impairment testing arising from changes in price assumptions and/
or production volumes up to a combined effect on revenue of 10% in all future years.
Revenue reductions of this magnitude in isolation could indicatively lead to a reduction in the carrying amount of bp’s Upstream oil and gas properties
in the range of $6-7 billion, which is approximately 5-6% of the net book value of property, plant and equipment as at 31 December 2020.
Revenue increases of this magnitude in isolation could indicatively lead to an increase in the carrying amount of bp’s Upstream oil and gas properties
in the range of $4-5 billion, which is approximately 3-4% of the net book value of property, plant and equipment as at 31 December 2020. This
potential increase in the carrying amount would arise due to reversals of previously recognized impairments.
These sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be recognized
as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of development. For
example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The above sensitivity analyses therefore do not reflect
a linear relationship between revenue and value that can be extrapolated. The interdependency of these inputs and risk factors plus the diverse
characteristics of our Upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall recoverable
amount is impacted by changes to the price assumptions or production volumes.
Management also tested the impact of a one percentage point change in the discount rate used for value-in-use impairment testing of Upstream oil
and gas properties. If the discount rate was one percentage point higher across all tests performed, the impairment charge recognized in 2020 would
have been approximately $2.4 billion higher. If the discount rate was one percentage point lower, the impairment charge recognized would have been
approximately $2.7 billion lower.
Goodwill
Irrespective of whether there is any indication of impairment, bp is required to test annually for impairment of goodwill acquired in business
combinations. The group carries goodwill of approximately $12.5 billion on its balance sheet (2019 $11.9 billion), principally relating to the Atlantic
Richfield, Burmah Castrol, Devon Energy and Reliance transactions. Sensitivities and additional information relating to impairment testing of goodwill
in the Upstream segment are provided in Note 14.
Inventories
Inventories, other than inventories held for short-term trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by
the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value is
determined by reference to prices existing at the balance sheet date, adjusted where the sale of inventories after the reporting period gives evidence
about their net realizable value at the end of the period.
Inventories held for short-term trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income
statement.
Supplies are valued at the lower of cost on a weighted average basis and net realizable value.
bp Annual Report and Form 20-F 2020
167
1. Significant accounting policies, judgements, estimates and assumptions – continued
Leases
Agreements that convey the right to control the use of an identified asset for a period of time in exchange for consideration are accounted for as
leases. The right to control is conveyed if bp has both the right to obtain substantially all of the economic benefits from, and the right to direct the use
of, the identified asset throughout the period of use. An asset is identified if it is explicitly or implicitly specified by the agreement and any substitution
rights held by the lessor over the asset are not considered substantive.
Agreements that convey the right to control the use of an intangible asset including rights to explore for or use hydrocarbons are not accounted for as
leases. See significant accounting policy: intangible assets.
A lease liability is recognized on the balance sheet on the lease commencement date at the present value of future lease payments over the lease
term. The discount rate applied is the rate implicit in the lease if readily determinable, otherwise an incremental borrowing rate is used. The incremental
borrowing rate is determined based on factors such as the group’s cost of borrowing, lessee legal entity credit risk, currency and lease term. The lease
term is the non-cancellable period of a lease together with any periods covered by an extension option that bp is reasonably certain to exercise, or
periods covered by a termination option that bp is reasonably certain not to exercise. The future lease payments included in the present value
calculation are any fixed payments, payments that vary depending on an index or rate, payments due for the reasonably certain exercise of options and
expected residual value guarantee payments. Repayments of principal are presented as financing cash flows and payments of interest are presented as
operating cash flows.
Payments that vary based on factors other than an index or a rate such as usage, sales volumes or revenues are not included in the present value
calculation and are recognized in the income statement and presented as operating cash flows. The lease liability is recognized on an amortized cost
basis with interest expense recognized in the income statement over the lease term, except for where capitalized as exploration, appraisal or
development expenditure.
The right-of-use asset is recognized on the balance sheet as property, plant and equipment at a value equivalent to the initial measurement of the lease
liability adjusted for lease prepayments, lease incentives, initial direct costs and any restoration obligations. The right-of-use asset is depreciated
typically on a straight-line basis over the lease term. The depreciation charge is recognized in the income statement except for where capitalized as
exploration, appraisal or development expenditure. Right-of-use assets are assessed for impairment in line with the accounting policy for impairment of
property, plant and equipment, intangible assets and goodwill.
Agreements may include both lease and non-lease components. Payments for lease and non-lease components are allocated on a relative stand-alone
selling price basis except for leases of retail service stations where the group has elected not to separate non-lease payments from the calculation of
the lease liability and right-of-use asset.
If the lease term at commencement of the agreement is less than 12 months, a lease liability and right-of-use asset are not recognized, and a lease
expense is recognized in the income statement on a straight-line basis.
If a significant event or change in circumstances, within the control of bp, arises that affects the reasonably certain lease term or there are changes to
the lease payments, the present value of the lease liability is remeasured using the revised term and payments, with the right-of-use asset adjusted by
an equivalent amount.
Modifications to a lease agreement beyond the original terms and conditions are accounted for as a re-measurement of the lease liability with a
corresponding adjustment to the right-of-use asset. Any gain or loss on modification is recognized in the income statement. Modifications that increase
the scope of the lease at a price commensurate with the stand-alone selling price are accounted for as a separate new lease.
The group recognizes the full lease liability, rather than its working interest share, for leases entered into on behalf of a joint operation if the group has
the primary responsibility for making the lease payments. This may be the case if for example bp, as operator of the joint operation, is the sole
signatory to the lease. In such cases, bp’s working interest share of the right-of-use asset is recognized if it is jointly controlled by the group and the
other joint operators, and a receivable is recognized for the share of the asset transferred to the other joint operators. If bp is a non-operator, a payable
to the operator is recognized if they have the primary responsibility for making the lease payments and bp has joint control over the right-of-use asset,
otherwise no balances are recognized.
Financial assets
Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not measured at fair value
through profit or loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their
classification, as set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive
cash flows have been transferred to a third party and either substantially all of the risks and rewards of the asset have been transferred, or substantially
all the risks and rewards of the asset have neither been retained nor transferred but control of the asset has been transferred. This includes the
derecognition of receivables for which discounting arrangements are entered into.
The group classifies its financial asset debt instruments as measured at amortized cost, fair value through other comprehensive income or fair value
through profit or loss. The classification depends on the business model for managing the financial assets and the contractual cash flow characteristics
of the financial asset.
Financial assets measured at amortized cost
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual
cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the
effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized
or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables.
Financial assets measured at fair value through other comprehensive income
Financial assets are classified as measured at fair value through other comprehensive income when they are held in a business model the objective of
which is both to collect contractual cash flows and sell the financial assets, and the contractual cash flows represent solely payments of principal and
interest.
Financial assets measured at fair value through profit or loss
Financial assets are classified as measured at fair value through profit or loss when the asset does not meet the criteria to be measured at amortized
cost or fair value through other comprehensive income. Such assets are carried on the balance sheet at fair value with gains or losses recognized in the
income statement. Derivatives, other than those designated as effective hedging instruments, are included in this category.
168
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Investments in equity instruments
Investments in equity instruments are subsequently measured at fair value through profit or loss unless an election is made on an instrument-by-
instrument basis to recognise fair value gains and losses in other comprehensive income.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses
arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Cash equivalents
Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of
changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets
measured at amortized cost or, in the case of certain money market funds, fair value through profit or loss.
Impairment of financial assets measured at amortized cost
The group assesses on a forward-looking basis the expected credit losses associated with financial assets classified as measured at amortized cost at
each balance sheet date. Expected credit losses are measured based on the maximum contractual period over which the group is exposed to credit
risk. As lifetime expected credit losses are recognized for trade receivables and the tenor of substantially all other in-scope financial assets is less than
12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses for the group. The
measurement of expected credit losses is a function of the probability of default, loss given default and exposure at default. The expected credit loss is
estimated as the difference between the asset’s carrying amount and the present value of the future cash flows the group expects to receive
discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is adjusted, with the amount of the impairment gain
or loss recognized in the income statement.
A financial asset or group of financial assets classified as measured at amortized cost is considered to be credit-impaired if there is reasonable and
supportable evidence that one or more events that have a detrimental impact on the estimated future cash flows of the financial asset (or group of
financial assets) have occurred. Financial assets are written off where the group has no reasonable expectation of recovering amounts due.
Equity instruments
Instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangements. Instruments that
cannot be settled in the group’s own equity instruments and that include no contractual obligation to deliver cash or another financial asset or to
exchange financial assets or financial liabilities with another entity that are potentially unfavourable are classified as equity. Equity instruments issued by
the group are recognized at the proceeds received, net of direct issue costs.
Financial liabilities
Financial liabilities are recognized when the group becomes party to the contractual provisions of the instrument. The group derecognizes financial
liabilities when the obligation specified in the contract is discharged, cancelled or expired. The measurement of financial liabilities depends on their
classification, as follows:
Financial liabilities measured at fair value through profit or loss
Financial liabilities that meet the definition of held for trading are classified as measured at fair value through profit or loss. Such liabilities are carried on
the balance sheet at fair value with gains or losses recognized in the income statement. Derivatives, other than those designated as effective hedging
instruments, are included in this category.
Derivatives designated as hedging instruments in an effective hedge
Derivatives designated as hedging instruments in an effective hedge are carried on the balance sheet at fair value. The treatment of gains and losses
arising from revaluation is described below in the accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings
this is typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is
calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or
cancellation of liabilities are recognized in interest and other income and finance costs respectively.
This category of financial liabilities includes trade and other payables and finance debt.
Significant judgement: supplier financing arrangements
The group’s trade payables include some supplier arrangements that utilize letter of credit facilities. Judgement is required to assesses the payables
subject to these arrangements to determine whether they should continue to be classified as trade payables and give rise to operating cash flows or
finance debt and financing cash flows. The criteria used in making this assessment include the payment terms for the amount due relative to terms
commonly seen in the markets in which bp operates and whether the arrangements significantly change the nature of the liability. Liabilities subject to
these arrangements with payment terms of up to approximately 60 days are generally considered to be trade payables and give rise to operating cash
flows. See Note 29 - Liquidity risk for further information.
Financial guarantees
The group issues financial guarantee contracts to make specified payments to reimburse holders for losses incurred because certain associates, joint
ventures or third-party entities fail to make payments when due in accordance with the original or modified terms of a debt instrument such as a loan.
The liability for a financial guarantee contract is initially measured at fair value and subsequently measured at the higher of the contract’s estimated
expected credit loss and the amount initially recognized less, where appropriate, cumulative amortization.
Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and
commodity prices, as well as for trading purposes. These derivative financial instruments are recognized initially at fair value on the date on which a
derivative contract is entered into and subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as
liabilities when the fair value is negative.
bp Annual Report and Form 20-F 2020
169
1. Significant accounting policies, judgements, estimates and assumptions – continued
Contracts to buy or sell a non-financial item (for example, oil, oil products, gas or power) that can be settled net in cash, with the exception of contracts
that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group’s expected
purchase, sale or usage requirements, are accounted for as financial instruments. Gains or losses arising from changes in the fair value of derivatives
that are not designated as effective hedging instruments are recognized in the income statement.
If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is
not recognized in the income statement but is deferred on the balance sheet and is commonly known as a ‘day-one gain or loss’. This deferred gain or
loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using observable
market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation subsequent to the initial
valuation at inception of a contract are recognized immediately in the income statement.
For the purpose of hedge accounting, hedges are classified as:
• Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.
• Cash flow hedges when hedging exposure to variability in cash flows that is attributable to either a particular risk associated with a recognized asset
or liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking
the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged,
the existence at inception of an economic relationship and subsequent measurement of the hedging instrument's effectiveness in offsetting the
exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk, the hedge ratio and sources of hedge ineffectiveness.
Hedges meeting the criteria for hedge accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk
being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss, where it offsets. The group applies fair
value hedge accounting when hedging interest rate risk and certain currency risks on fixed rate finance debt.
Fair value hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes
when the risk management objective changes or when the hedging instrument is sold, terminated or exercised. The accumulated adjustment to the
carrying amount of a hedged item at such time is then amortized prospectively to profit or loss as finance interest expense over the hedged item's
remaining period to maturity.
Cash flow hedges
The effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income, while the ineffective portion is
recognized in profit or loss. Amounts reported in other comprehensive income are reclassified to the income statement when the hedged transaction
affects profit or loss.
Where the hedged item is a highly probably forecast transaction that results in the recognition of a non-financial asset or liability, such as a forecast
foreign currency transaction for the purchase of property, plant and equipment, the amounts recognized within other comprehensive income are
transferred to the initial carrying amount of the non-financial asset or liability. Where the hedged item is an equity investment, the amounts recognized
in other comprehensive income remain in the separate component of equity until the hedged cash flows affect profit or loss. Where the hedged item is
recognized directly in profit or loss, the amounts recognized in other comprehensive income are reclassified to production and manufacturing expenses
or sales and other operating revenues as appropriate.
Cash flow hedge accounting is discontinued only when the hedging relationship or a part thereof ceases to meet the qualifying criteria. This includes
when the designated hedged forecast transaction or part thereof is no longer considered to be highly probable to occur, or when the hedging
instrument is sold, terminated or exercised without replacement or rollover. When cash flow hedge accounting is discontinued amounts previously
recognized within other comprehensive income remain in equity until the forecast transaction occurs and are reclassified to profit or loss or transferred
to the initial carrying amount of a non-financial asset or liability as above. If the forecast transaction is no longer expected to occur, amounts previously
recognized within other comprehensive income will be immediately reclassified to profit or loss.
Costs of hedging
The foreign currency basis spread of cross-currency interest rate swaps are excluded from hedge designations and accounted for as costs of hedging.
Changes in fair value of the foreign currency basis spread are recognized in other comprehensive income to the extent that they relate to the hedged
item. For time-period related hedged items, the amount recognized in other comprehensive income is amortized to profit or loss on a straight line basis
over the term of the hedging relationship.
Fair value measurement
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The
group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their
measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either
directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or
liability reflecting significant modifications to observable related market data or bp’s assumptions about pricing by market participants.
170
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant estimate and judgement: derivative financial instruments
In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market-
corroborated data. This primarily applies to the group’s longer-term derivative contracts. The majority of these contracts are valued using models with
inputs that include price curves for each of the different products that are built up from available active market pricing data (including volatility and
correlation) and modelled using the maximum available external information. Additionally, where limited data exists for certain products, prices are
determined using historical and long-term pricing relationships. The use of alternative assumptions or valuation methodologies may result in
significantly different values for these derivatives. A reasonably possible change in the price assumptions used in the models relating to index price
would not have a material impact on net assets and the Group income statement primarily as a result of offsetting movements between derivative
assets and liabilities. For more information, including the carrying amounts of level 3 derivatives, see Note 30.
In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative or to determine
appropriate presentation and classification of transactions in certain cases. In particular contracts to buy and sell LNG are not considered to meet the
definition as they are not considered capable of being net settled due to a lack of liquidity in the LNG market and the inability or lack of history of net
settlement and so are accounted for on an accruals basis, rather than as a derivative.
Offsetting of financial assets and liabilities
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a legally
enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the liability
simultaneously. A right of set off is the group’s legal right to settle an amount payable to a creditor by applying against it an amount receivable from the
same counterparty. The relevant legal jurisdiction and laws applicable to the relationships between the parties are considered when assessing whether
a current legally enforceable right to set off exists.
Provisions and contingencies
Provisions are recognized when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate
that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of
time is recognized within finance costs. Provisions are discounted using a nominal discount rate of 2.5% (2019 2.5%).
Provisions are split between amounts expected to be settled within 12 months of the balance sheet date (current) and amounts expected to be settled
later (non-current).
Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within the control of the group, or
present obligations where it is not probable that an outflow of resources will be required or the amount of the obligation cannot be measured with
sufficient reliability. Contingent liabilities are not recognized in the consolidated financial statements but are disclosed unless the possibility of an
outflow of economic resources is considered remote.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or an
item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a
new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or
installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also
crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations;
an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations,
for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance with local
conditions and requirements. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their economic lives
is estimated using existing technology, at future prices, depending on the expected timing of the activity, and discounted using the nominal discount
rate.
An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration or
appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the
same rate as the rest of the asset. Other than the unwinding of discount on or utilisation of the provision, any change in the present value of the
estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is generating or is expected to
generate future economic benefits.
Environmental expenditures and liabilities
Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of those
assets. Expenditures that relate to an existing condition caused by past operations that do not contribute to future earnings are expensed.
Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing
of recognition of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.
The amount recognized is the best estimate of the expenditure required to settle the obligation. Provisions for environmental liabilities have been
estimated using existing technology, at future prices and discounted using a nominal discount rate.
Emissions
Liabilities for emissions are recognized when the cumulative volumes of gases emitted by the group at the end of the reporting period exceed the
allowances granted free of charge held for own use or a set baseline for emissions. The provision is measured at the best estimate of the expenditure
required to settle the present obligation at the balance sheet date. It is based on the excess of actual emissions over the free allowances held or set
baseline in tonnes (or other appropriate quantity) and is valued at the actual cost of any allowances that have been purchased and held for own use on a
first-in-first-out (FIFO) basis, and, if insufficient allowances are held, for the remaining requirement on the basis of the spot market price of allowances
at the balance sheet date. The cost of allowances purchased to cover a shortfall is recognized separately on the balance sheet as an intangible asset
unless the emission allowances acquired or generated by the group are risk-managed by the integrated supply and trading function, then they are
recognized on the balance sheet as inventory.
bp Annual Report and Form 20-F 2020
171
1. Significant accounting policies, judgements, estimates and assumptions – continued
Restructuring provisions
The reinvent bp programme, expected to reduce headcount by around 10,000 positions, has resulted in recognition of provisions where a detailed
formal plan exists, and a valid expectation of risk of redundancy has been made to those affected but where the specific outcomes remain uncertain .
Where formal redundancy offers have been made, the obligations for those amounts are reported as payables and, if not, as provisions if unpaid at the
year-end.
Significant judgements and estimates: provisions
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives.
The largest decommissioning obligations facing bp relate to the plugging and abandonment of wells and the removal and disposal of oil and natural
gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements that
will have to be met when the removal event occurs are uncertain. Decommissioning technologies and costs are constantly changing, as are political,
environmental, safety and public expectations. The timing and amounts of future cash flows are subject to significant uncertainty and estimation is
required in determining the amounts of provisions to be recognized. Any changes in the expected future costs are reflected in both the provision and
the asset.
If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will be unable
to meet their decommissioning obligations, whether bp would then be responsible for decommissioning, and if so the extent of that responsibility.
The group has assessed that no material decommissioning provisions should be recognized as at 31 December 2020 (2019 no material provisions) for
assets sold to third parties where the sale transferred the decommissioning obligation to the new owner.
Decommissioning provisions associated with downstream refineries are generally not recognized, as the potential obligations cannot be measured,
given their indeterminate settlement dates.Obligations may arise if refineries cease manufacturing operations and any such obligations would be
recognized in the period when sufficient information becomes available to determine potential settlement dates.
The group performs periodic reviews of its downstream refineries for any changes in facts and circumstances including those relating to the energy
transition, that might require the recognition of a decommissioning provision.
The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected
plans for remediation. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public
expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.
The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually. The interest rate used
in discounting the cash flows is reviewed quarterly. The nominal interest rate used to determine the balance sheet obligations at the end of 2020 was
2.5% (2019 2.5%), which was based on long-dated US government bonds. The weighted average period over which decommissioning and
environmental costs are generally expected to be incurred is estimated to be approximately 18 years (2019 18 years) and 6 years (2019 6 years)
respectively. Costs at future prices are determined by applying an inflation rate of 1.5% (2019 1.5%) to decommissioning costs and 2% (2019 2%) for
all other provisions. A lower rate is applied to decommissioning as certain costs are expected to remain fixed at current or past prices.
Further information about the group’s provisions is provided in Note 23. Changes in assumptions in relation to the group's provisions could result in a
material change in their carrying amounts within the next financial year. A 0.5 percentage point decrease in the nominal discount rate applied could
increase the group’s provision balances by approximately $1.3 billion (2019 $1.4 billion). The pre-tax impact on the group income statement would be
a charge of approximately $0.5 billion.
The discounting impact on the group's Upstream decommissioning provisions of a two-year change in the timing of expected future decommissioning
expenditures would not be material. Management currently does not consider a change of greater than two years to be reasonably possible in the
next financial year.
If all expected future decommissioning expenditures were 10% higher, the group's Upstream decommissioning provisions would increase by
approximately $1.4 billion and a pre-tax charge of approximately $0.5 billion would be recognized.
As described in Note 33, the group is subject to claims and actions for which no provisions have been recognized. The facts and circumstances
relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized or revised.
Accordingly, significant management judgement relating to provisions and contingent liabilities is required, since the outcome of litigation is difficult to
predict.
Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are
rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the balance sheet date are
valued on an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests.
The accounting policies for share-based payments and for pensions and other post-retirement benefits are described below.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value of the equity instruments on the date on which they
are granted and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the
award. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, valuation model. In valuing
equity-settled transactions, no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market
conditions). Non-vesting conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date
fair value, and failure to meet a non-vesting condition, where this is within the control of the employee is treated as a cancellation and any remaining
unrecognized cost is expensed.
For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at
the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods and services received
cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted.
172
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Cash-settled transactions
The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding
liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in
fair value recognized in the income statement.
Pensions and other post-retirement benefits
The cost of providing benefits under the group’s defined benefit plans is determined separately for each plan using the projected unit credit method,
which attributes entitlement to benefits to the current period to determine current service cost and to the current and prior periods to determine the
present value of the defined benefit obligation. Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future
obligations as a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a
change.
Net interest expense relating to pensions and other post-retirement benefits, which is recognized in the income statement, represents the net change
in present value of plan obligations and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to
the present value of the benefit obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account
expected changes in the obligation or plan assets during the year.
Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts
included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently
reclassified to profit and loss.
The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value
of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the
obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price.
Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, either by way of a refund from the plan or reductions in
future contributions to the plan.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate: pensions and other post-retirement benefits
Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates when measuring the group's
pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties.
Pensions and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to
determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group's balance sheet, and pension
and other post-retirement benefit expense for the following year.
The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels.
Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant
effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in
material changes to the carrying amounts of the group's pension and other post-retirement benefit obligations within the next financial year, in
particular for the UK, US and Eurozone plans. Any differences between these assumptions and the actual outcome will also affect future net income
and net assets.
The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and
obligation used are provided in Note 24.
Income taxes
Income tax expense represents the sum of current tax and deferred tax.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in
equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is
determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are
taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated using tax
rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities
and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for all taxable temporary differences except:
• Where the deferred tax liability arises on the initial recognition of goodwill.
• Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the
time of the transaction, affects neither accounting profit nor taxable profit or loss.
• In respect of taxable temporary differences associated with investments in subsidiaries and associates and interests in joint arrangements, where
the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in
the foreseeable future.
Deferred tax assets are recognized for deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it
is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and
unused tax losses can be utilized, except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition
of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable
profit or loss. In respect of deductible temporary differences associated with investments in subsidiaries and associates and interests in joint
arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable
future and taxable profit will be available against which the temporary differences can be utilized.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable or increased
to the extent that it is probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
bp Annual Report and Form 20-F 2020
173
1. Significant accounting policies, judgements, estimates and assumptions – continued
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is
settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities
are not discounted.
Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities and
when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different
taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities
simultaneously.
Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment, income taxes
are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected within the carrying amount of
the applicable tax asset or liability using either the most likely amount or an expected value, depending on which method better predicts the resolution
of the uncertainty.
The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many jurisdictions
throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can
take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to determine whether
provisions for income taxes are required and, if so, estimation is required of the amounts that could be payable.
In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable profit.
However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax
losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case and estimates are required to be made
of the amount of future taxable profits that will be available.Such judgements are inherently impacted by estimates affecting future taxable profits such
as oil and natural gas prices and decommissioning expenditure, see significant judgements and estimates: recoverability of asset carrying values and
provisions
Management do not assess there to be a significant risk of a material change to the group’s tax provisioning or recognition of deferred tax assets within
the next financial year, however the tax position remains inherently uncertain and therefore subject to change. To the extent that actual outcomes differ
from management’s estimates, income tax charges or credits, and changes in current and deferred tax assets or liabilities, may arise in future periods.
For more information see Note 9 and Note 33.
Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax).
Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are recognized in
the income statement in accordance with the applicable accounting policy such as Provisions and contingencies. No new significant judgements were
made in 2020 in this regard.
Customs duties and sales taxes
Customs duties and sales taxes that are passed on or charged to customers are excluded from revenues and expenses. Assets and liabilities are
recognized net of the amount of customs duties or sales tax except:
• Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are recognized
as part of the cost of acquisition of the asset.
• Receivables and payables are stated with the amount of customs duty or sales tax included.
The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.
Own equity instruments – treasury shares
The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity. Treasury shares represent bp shares
repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee Share Ownership Plans (ESOPs) to
meet the future requirements of the employee share-based payment plans are treated in the same manner as treasury shares and are, therefore,
included in the consolidated financial statements as treasury shares. The cost of treasury shares subsequently sold or reissued is calculated on a
weighted-average basis. Consideration, if any, received for the sale of such shares is also recognized in equity. No gain or loss is recognized in the
income statement on the purchase, sale, issue or cancellation of equity shares. Shares repurchased under the share buy-back programme which are
immediately cancelled are not shown as treasury shares, but are shown as a deduction from the profit and loss account reserve in the group statement
of changes in equity.
Revenue and other income
Revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring control of a promised
good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items
usually coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance
obligations at a point in time; the amounts of revenue recognized relating to performance obligations satisfied over time are not significant.
When, or as, a performance obligation is satisfied, the group recognizes as revenue the amount of the transaction price that is allocated to that
performance obligation. The transaction price is the amount of consideration to which the group expects to be entitled. The transaction price is
allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.
Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognized based
on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after delivery has
been made. Revenue from such contracts is initially recognized based on relevant prices at the time of delivery and subsequently adjusted as
appropriate. All revenue from these contracts, both that recognized at the time of delivery and that from post-delivery price adjustments, is disclosed
as revenue from contracts with customers.
Certain forward contracts entered into by the group that result in physical delivery of products such as crude oil, natural gas and refined products are
required to be accounted for as derivative financial instruments. Revenue recognized relating to such contracts when physical delivery occurs is
measured at the contractual transaction price plus the carrying amount of the related derivative at the date of settlement and presented as other
operating revenues. Changes in the fair value of derivative assets and liabilities prior to physical delivery are also classified as other operating revenues.
See also Other significant accounting policy changes - IFRIC agenda decision on IFRS 9 'Financial instruments' below.
174
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Where forward sale and purchase contracts for oil, natural gas or power have been determined to be for short-term trading purposes, the associated
sales and purchases are reported net within sales and other operating revenues whether or not physical delivery has occurred.
Physical exchanges with counterparties in the same line of business in order to facilitate sales to customers are reported net, as are sales and
purchases made with a common counterparty, as part of an arrangement similar to a physical exchange.
Where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is recognized but no
purchase or sale is recorded.
Interest income is recognized as the interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash
receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).
Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.
Contract asset and contract liability balances are included within amounts presented for trade receivables and other payables respectively.
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial
period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their
intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.
Updates to significant accounting policies
Impact of new International Financial Reporting Standards
bp adopted ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial instruments’ and IFRS 7 ‘Financial instruments:
Disclosures’’ with effect from 1 January 2020. There are no other new or amended standards or interpretations adopted during the year that have a
significant impact on the consolidated financial statements.
'Interest Rate Benchmark Reform – Phase I’
Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter-
bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. Uncertainty around the method and timing of transition from
Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting can be applied to
certain hedging relationships.
This first phase of amendments to IFRS 9 provide temporary relief from applying specific hedge accounting requirements to hedging relationships
directly affected by interest rate benchmark reforms.
In accordance with the transition provisions, the amendments have been adopted retrospectively to hedging relationships that existed at the start of
the current reporting period and have been applied to new hedging relationships designated after that date.
The reliefs have meant that the uncertainty over the interest rate benchmark reforms has not resulted in discontinuation of hedge accounting for any of
bp’s fair value hedges.
See Note 29 Financial instruments and financial risk factors - interest rate risk and Note 30 Derivative financial instruments - Fair value hedges for
further information.
Impact of new International Financial Reporting Standards - Not yet adopted
The following pronouncements from the IASB have not been adopted by the group in these financial statements as they will only become effective for
future financial reporting periods. There are no other standards, amendments or interpretations in issue but not yet adopted that the directors anticipate
will have a material effect on the reported income or net assets of the group.
IFRS 17 ' Insurance Contracts'
IFRS 17 'Insurance Contracts' provides a new general model for accounting for contracts where the issuer accepts significant insurance risk from
another party and agrees to compensate that party if a future uncertain event adversely affects them. IFRS 17 replaces IFRS 4 'Insurance Contracts'
and will be effective for bp for the financial reporting period commencing 1 January 2023. The standard has not yet been endorsed by the UK and the
EU. bp's assessment of the impact of IFRS 17 is at an initial stage but it is not expected to have a significant effect on future financial reporting.
‘Interest Rate Benchmark Reform – Phase II’
Amendments to IFRS 9, IFRS 7, IFRS 4 and IFRS 16 ‘Leases’ were issued by the IASB in August 2020 to provide practical expedients and reliefs in
relation to modifications of financial instruments and leases that arise from transition from IBORs to RFRs. Phase II also provides further reliefs to
hedge accounting requirements. These amendments were effective for bp from 1 January 2021. The amendments have been endorsed by the UK and
by the EU.
bp’s working group on interest rate benchmark reform is monitoring and managing the transition to alternative benchmark rates and is currently
assessing the impact on contracts and arrangements that are linked to existing interest rate benchmarks for example, borrowings, leases and derivative
contracts. bp is also participating on external committees and task forces dedicated to interest rate benchmark reform.
Other changes to significant accounting policies
Physically settled derivative contracts
In March 2019, IFRIC issued an agenda decision on the application of IFRS 9 to the physical settlement of contracts to buy or sell a non-financial item,
such as commodities, that are not accounted for as 'own-use' contracts. IFRIC concluded that such contracts are settled by the delivery or receipt of a
non-financial item in exchange for both cash and the settlement of the derivative asset or liability.
bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of a derivative financial
instrument. As described in the group's accounting policy for revenue in bp Annual Report and Form 20-F 2019, revenue recognized at the time such
contracts were physically settled was measured at the contractual transaction price and was presented together with revenue from contracts with
customers in those financial statements.
bp Annual Report and Form 20-F 2020
175
1. Significant accounting policies, judgements, estimates and assumptions – continued
bp changed its accounting policy for these contracts, in accordance with the conclusions included in the agenda decision, with effect from 1 April 2020,
as follows:
• Revenues and purchases from such contracts are measured at the contractual transaction price plus the carrying amount of the related derivative at
the date of settlement. Realized derivative gains and losses on physically settled derivative contracts are included in other revenues.
• There is no significant effect on current period or comparative information for ‘Sales and other operating revenues’ and ‘Purchases’ as presented in
the group income statement, therefore no comparative information has been re-stated.
• There is no significant effect on net assets or on comparative information for ‘Profit before taxation’ or ‘Profit after taxation’ as presented in the group
income statement.
In addition, bp chose to change its presentation of revenues from physically settled derivative sales contracts from 1 January 2020. Revenues from
physically settled derivative sales contracts are no longer presented together with revenue from contracts with customers. In these financial
statements they are now presented as other revenues. Comparative information in Note 6 for revenue from contracts with customers and other
revenues have been re-presented to align with the current period as set out below.
2019
(previously
reported)
2019 (re-
presented –
see note 6)
Presentational
adjustments
2018
(previously
reported)
2018 (re-
presented –
see note 6)
Presentational
adjustments
$ million
Crude oil
Oil products
Natural gas, LNG and NGLs
Non-oil products and other revenues from contracts with customers
Revenue from contracts with customers
Other operating revenues
Total sales and other operating revenues
62,130
20,167
13,254
9,141
180,528 102,408
18,909
12,169
54,945
86,951
1,251
1,279
276,079 142,627 133,452 296,255 151,829 144,426
(144,426)
—
10,331
65,276
52,989
78,120 195,466 108,515
20,494
21,745
12,489
13,768
2,501 146,927
— 298,756 298,756
2,318 135,770
278,397 278,397
1,258
1,085
(133,452)
Voluntary changes to significant accounting policies - not yet adopted
Net presentation of revenues and purchases relating to physically settled derivative contracts from 1 January 2021
As described above, bp routinely enters into transactions for the sale and purchase of commodities that are physically settled and meet the definition of
a derivative financial instrument. These contracts are within the scope of IFRS 9 and as such, prior to settlement, changes in the fair value of these
derivative contracts are presented as gains and losses within other operating revenues. The group currently presents revenues and purchases for such
contracts on a gross basis in the group income statement upon physical settlement. These transactions have historically represented a substantial
portion of the revenues and purchases reported in the group’s consolidated financial statements.
The change in strategic direction of the group supported by organisational changes to implement the strategy from 1 January 2021, results in the group
determining that the revenue and corresponding purchases relating to such transactions should be presented net as gains or losses within other
operating revenues. Additionally the group’s trading activity has continued to evolve over time from one of capturing third party physical trades to
provide flow assurance to one with increasing levels of optimisation, taking advantage of price volatility and fluctuations in demand and supply, which
will continue under the new strategy, further supporting the change in presentation. The new presentation provides reliable and more relevant
information for users of the accounts as the group’s revenue recognition will be more closely aligned with its assessment of ‘Scope 3’ emissions from
its products, its ‘Net Zero’ ambition and how management monitors and manages performance of such contracts. Comparative information for Sales
and other operating revenues and purchases for 2019 and 2020 will be restated and will be presented under the new policy alongside group’s 2021
financial information.
Change in segmentation
During the first quarter of 2021, the group's reportable segments changed consistent with a change in the way that resources are allocated and
performance is assessed by the chief operating decision maker, who for bp is the group chief executive, from that date. From the first quarter of 2021,
the group's reportable are gas & low carbon energy, oil production & operations, customers & products, and Rosneft. At 31 December 2020, the
group's reportable segments were Upstream, Downstream and Rosneft.
Gas & low carbon energy comprises regions with upstream businesses that predominantly produce natural gas, gas trading activities and the group's
renewables businesses, including biofuels, solar and wind. Gas producing regions were previously in the Upstream segment. The group's renewables
businesses were previously part of 'Other businesses and corporate'.
Oil production & operations comprises regions with upstream activities that predominantly produce crude oil. These activities were previously in the
Upstream segment.
Customers & products comprises the group's convenience and mobility business, which manages the sale of fuels to wholesale and retail customers,
convenience products, aviation fuels, and Castrol lubricants; and refining, supply and trading. The petrochemicals business will also be reported in
restated comparative information as part of the customers and products segment up to its sale in December 2020. The customers & products segment
is, therefore, substantially unchanged from the former Downstream segment with the exception of the Petrochemicals disposal.
The Rosneft segment is unchanged and continues to include equity-accounted earnings from the group's investment in Rosneft.
The segment measure of profit or loss continues to be replacement cost profit or loss before interest and tax, which reflects the replacement cost of
supplies by excluding from profit or loss before interest and tax inventory holding gains and losses. See Note 5 for further information.
In the group's financial reporting for 2021, comparative information for 2019 and 2020 will be restated to reflect the changes in reportable segments.
Reporting under the new segment structure will begin with the first quarter 2021 interim financial statements.
Segmental information presented in these financial statements is based on the segment structure as at 31 December 2020.
176
bp Annual Report and Form 20-F 2020
Financial statements
2. Non-current assets held for sale
The carrying amount of assets classified as held for sale at 31 December 2020 is $1,326 million (2019 $7,465 million), with associated liabilities of $46
million (2019 $1,393 million).
Upstream segment
The balance consists primarily of a 20% participating interest from bp’s 60% participating interest in Block 61 in Oman. As announced on 1 February
2021, bp has agreed to sell this interest to PTT Exploration and Production Public Company Limited of Thailand for a total consideration of up to
$2.6 billion, subject to final adjustments. Under the terms of the agreement, bp will receive $2,450 million on completion, with up to an additional
$140 million receivable contingent on pre-agreed future conditions. Subject to approvals, the transaction is expected to complete during 2021. Assets
of $1,298 million and associated liabilities of $10 million have been classified as held for sale in the group balance sheet at 31 December 2020.
Transactions that have been classified as held for sale during 2020, but were completed by 31 December 2020, are described below.
Downstream segment
On 29 June 2020 bp announced that it had agreed to sell its global petrochemicals business to INEOS for a total consideration of $5 billion, subject to
customary closing adjustments. The assets and liabilities of the business were classified as held for sale from that date until the disposal completed on
31 December 2020. Under the terms of the agreement, INEOS paid bp a deposit of $400 million and a further $3.6 billion on completion less $0.1 billion
of third-party indebtedness remaining in petrochemicals on completion. The remaining $1 billion was received in February 2021. The business had
interests in manufacturing plants in Asia, Europe and the US, including interests held in equity-accounted entities. See note 4 for further information.
Upstream segment
On 27 August 2019, bp announced that it had agreed to sell its Alaska operations and interests to Hilcorp Energy for up to $5.6 billion, subject to
customary closing adjustments. The sale included bp’s upstream and midstream business in the state, including BP Exploration (Alaska) Inc., which
owned all of bp’s upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.’s 49% interest in the Trans Alaska Pipeline System (TAPS).
These assets and associated liabilities were classified as held for sale in the 31 December 2019 group balance sheet. The disposal of BP Exploration
(Alaska) Inc. completed on 30 June 2020. The disposal of TAPS completed on 18 December 2020.
bp received $800 million prior to or on completion of the disposals and has recognized a loan note with a principal amount of $2,100 million receivable
from Hilcorp. The group has also recognized other assets totalling $1,722 million as at 31 December 2020, principally in relation to the ‘earn-out’
provisions of the agreement. See note 4 for information on impairment charges relating to the Alaska business.
bp retained decommissioning liability relating to the TAPS, which will be partially offset by a 30% cost reimbursement from Hilcorp when incurred.
In November 2019, bp agreed to sell its interests in the San Juan basin in Colorado and New Mexico to IKAV. These assets and associated liabilities
were classified as held for sale in the 31 December 2019 group balance sheet. The transaction completed on 28 February 2020.
The total assets and liabilities held for sale at 31 December 2020 and 2019, which are all in the Upstream segment, are set out in the table below.
Property, plant and equipment
Goodwill
Intangible assets
Investments in associates
Inventories
Trade and other receivables
Assets classified as held for sale
Trade and other payables
Lease liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits
Liabilities directly associated with assets classified as held for sale
3. Business combinations and other significant transactions
Business combinations
2020
2020
1,099
199
—
—
—
28
1,326
(36)
—
(10)
—
(46)
$ million
2019
6,359
—
610
43
318
135
7,465
(33)
(280)
(1,012)
(68)
(1,393)
The group undertook a number of business combinations during 2020. The fair value of the net assets (including goodwill) and non-controlling interests
recognized were $617 million and $574 million, respectively. These principally related to an acquisition in our US Fuels business.
2019
As agreed as part of the original transaction, $3,480 million was paid in 2019 in respect of the 2018 acquisition of Petrohawk Energy Corporation from
BHP Billiton. A number of other individually insignificant business combinations were also undertaken by bp in 2019.
bp Annual Report and Form 20-F 2020
177
4. Disposals and impairment
The following amounts were recognized in the income statement in respect of disposals and impairments.
Gains on sale of businesses and fixed assets
Upstream
Downstream
Other businesses and corporate
Losses on sale of businesses and fixed assets, and closures
Upstream
Downstream
Other businesses and corporate
Impairment losses
Upstream
Downstream
Other businesses and corporate
Impairment reversals
Upstream
Downstream
Other businesses and corporate
Impairment and losses on sale of businesses and fixed assets, and closures
Disposals
Disposal proceeds and principal gains and losses on disposals by segment are described below.
Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposed
By business
Upstream
Downstream
Other businesses and corporate
2020
2019
360
2,320
194
2,874
143
50
—
193
2020
2019
383
296
2
681
12,917
840
32
13,789
(86)
—
(3)
(89)
14,381
2020
491
4,989
5,480
1,175
3,959
346
5,480
415
57
887
1,359
6,752
65
30
6,847
(131)
—
—
(131)
8,075
2019
500
1,701
2,201
2,048
152
1
2,201
$ million
2018
437
15
4
456
$ million
2018
707
59
11
777
400
12
254
666
(580)
(2)
(1)
(583)
860
$ million
2018
940
1,911
2,851
2,145
120
586
2,851
Proceeds from disposals of business in 2020 includes $3,888 million in respect of the disposal of the Petrochemical business and $347 million in
respect of the disposal of the Alaska business. At 31 December 2020, deferred consideration relating to disposals amounted to $1,291 million
receivable within one year (2019 $159 million and 2018 $35 million) and $2,402 million receivable after one year (2019 $125 million and 2018 $304
million). The deferred consideration principally relates to the disposals of our Petrochemical and Alaskan businesses. In addition, contingent
consideration receivable relating to disposals amounted to $1,999 million at 31 December 2020 (2019 $598 million and 2018 $893 million).The
contingent consideration at 31 December 2020 relates to the disposal of our Alaskan business and prior period disposals in the North Sea. These
amounts of contingent consideration are reported within Other investments on the group balance sheet - see Note 18 for further information.
Gains and losses on sale of businesses and fixed assets, and closures
Upstream
In 2020, gains principally resulted from adjustments to disposals in prior periods. Gains include $130 million from the disposal of our Alaska operations
and interests and $166 million fair value movements in relation to deferred and contingent consideration in relation to the Alaska disposal and prior
disposals in the North Sea. Losses included $134 million fair value movements in relation to deferred and contingent consideration arising from prior
period disposals in the North Sea, $120 million in relation to the likely disposal of an exploration asset, and $78 million from the disposal of certain
properties in the US.
In 2019, losses included $191 million fair value movements in relation to contingent consideration arising from the prior period disposal of the Bruce,
Keith and Devenick assets and $171 million in relation to severance costs associated with the divestment of our Alaskan business.
In 2018, gains principally resulted from the disposal of interests in the Bruce, Keith and Rhum fields in the UK North Sea, from the disposal of certain
properties in the US, and from adjustments to disposals in prior periods. Losses included $335 million resulting from the disposal of our interest in the
Magnus field and associated assets in the UK North Sea, $221 million from the disposal of our interest in the Greater Kuparuk Area in the US, and
adjustments to disposals in prior periods.
178
bp Annual Report and Form 20-F 2020
Financial statements
4. Disposals and impairment – continued
Downstream
In 2020, gains principally resulted from the $2.3 billion gain recognised on the disposal of our Petrochemicals business which completed in December
2020. Losses included $229 million in relation to cessation of manufacturing operations at the Kwinana Refinery following the decision to cease fuel
production.
Other businesses and corporate
In 2020 the gain on disposal of businesses and fixed assets was principally in respect of the sale and leaseback of our St James's Square London
headquarters - see Note 28 for further information.
In 2019 losses on disposal of businesses and fixed assets were principally in respect of the reclassification of accumulated foreign exchange losses
from reserves to the income statement upon the contribution of our Brazilian biofuels business to a new 50:50 joint venture BP Bunge Bioenergia.
In 2018 proceeds from disposals were principally in respect of life insurance policies in the US and wind farms within our US wind business.
Summarized financial information relating to the sale of businesses is shown in the table below.
The principal transactions categorized as a business disposal in 2020 were the sales of our Petrochemical and Alaskan businesses. See Note 2 for
further information.
The principal transaction categorized as a business disposal in 2019 was the sale of our interests in the Gulf of Suez oil concessions in Egypt.
The principal transaction categorized as a business disposal in 2018 was the disposal of our interest in the Greater Kuparuk Area in the US.
Non-current assets
Current assets
Non-current liabilities
Current liabilities
Total carrying amount of net assets disposed
Recycling of foreign exchange on disposal
Costs on disposal
Gains (losses) on sale of businesses
Alaska
5,143
693
(923)
(344)
4,569
—
(6)
4,563
260
4,823
(219)
(4,257)
347
Petrochemicals
2,592
846
(178)
(425)
2,835
(331)
(25)
2,479
2,414
4,893
—
(1,005)
3,888
2020
2019
Other
1,357
—
(538)
(13)
806
3
44
853
(104)
749
—
5
754
Total
9,092
1,539
(1,639)
(782)
8,210
(328)
13
7,895
2,570
10,465
(219)
(5,257)
4,989
1,653
507
(257)
(108)
1,795
880
190
2,865
(1,190)
1,675
(938)
964
1,701
$ million
2018
3,274
173
(250)
(97)
3,100
—
3
3,103
(221)
2,882
(282)
(689)
1,911
Total consideration
Non-cash consideration
Consideration received (receivable)a
Proceeds from the sale of businesses, net of cash disposedb
a In 2019 $633 million relates to deposits received in advance of the disposal of our Alaska business and certain assets in our BPX business.
b Proceeds are stated net of cash and cash equivalents disposed of $101 million (2019 $30 million and 2018 $15 million).
Impairments
Impairment losses and impairment reversals in each segment are described below. For information on significant estimates and judgements made in
relation to impairments see Impairment of property, plant and equipment, intangibles and goodwill within Note 1. See also Note 12, and Note 15 for
further information on impairments by asset category.
Upstream
Impairment losses and reversals in all years relate primarily to producing and midstream assets.
The 2020 impairment loss of $12,917 million primarily relates to losses incurred in respect of producing and development assets in the UK North Sea
($2,796 million), the US ($2,744 million), Trinidad ($2,416 million), Mauritania and Senegal ($1,909 million), India ($1,313 million) and Canada ($865
million). Impairment losses were primarily driven by a reduction in bp’s future oil and gas price assumptions and, to a lesser extent, certain technical
reserves revisions. The recoverable amount of the impaired CGUs in total is $33,415 million.
The principal CGUs on which significant impairment losses were incurred in 2020 were $1,909 million for Tortue in Mauritania and Senegal; $1,313
million for KGD6 in India; $1,181 million for Schiehallion in the UK North Sea; $1,044 million for Mahogany in Trinidad, $960 million for Cassia in
Trinidad; $1,011 million for Hawkville in BPX Energy; $747 million for ETAP in the UK North Sea and $742 million for Sunrise in Canada. The recoverable
amount for each of these CGUs was their value in use, which in total was $13,200 million. In addition, impairment losses of $939 million were incurred
relating to the disposal of bp’s business in Alaska. The recoverable amount of the Alaska business was its fair value less costs of disposal; see note 2
for further information.
The 2019 impairment losses of $6,752 million related to various assets, with the most significant charges arising in the US. Impairment losses arose
primarily as a result of the decision to dispose of certain assets, including $4,703 million in relation to completed and expected disposals in BPX Energy
and $1,264 million relating to the expected disposal of our Alaskan business; of these amounts $355 million primarily relates to impairment of
associated goodwill.
The 2018 impairment losses of $400 million related to a number of different assets, with the most significant charges arising in Australia and the US.
Impairment losses arose primarily as a result of changes to project activity, asset obsolescence and the decision to dispose of certain assets. The 2018
impairment reversals of $580 million related to a number of different assets, with the most significant reversals arising in the North Sea and Angola
following a change to decommissioning cost estimates.
Downstream
Impairment losses totalling $840 million, $65 million, and $12 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2020
principally relates to portfolio changes in the fuels business, including the conversion of Kwinana refinery to an import terminal. None of the impairment
charges were individually material.
bp Annual Report and Form 20-F 2020
179
4. Disposals and impairment – continued
Other businesses and corporate
Impairment losses totalling $32 million, $30 million, and $254 million were recognized in 2020, 2019 and 2018 respectively. The amount for 2018 is in
respect of assets within our US wind business in advance of their disposal in December 2018.
5. Segmental analysis
The group’s organizational structure reflects the various activities in which bp is engaged. At 31 December 2020, bp had three reportable segments:
Upstream, Downstream and Rosneft.
Upstream’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and
the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs).
Downstream’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals
products and related services to wholesale and retail customers.
bp’s interest in Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which the
investment is managed.
Other businesses and corporate comprises the biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities
worldwide.
The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that
the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for
the purposes of performance assessment and resource allocation. For bp, this measure of profit or loss is replacement cost profit or loss before
interest and tax which reflects the replacement cost of supplies by excluding from profit or loss before interest and tax inventory holding gains and
lossesa. Replacement cost profit or loss before interest and tax for the group is not a recognized measure under IFRS.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and
segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on
consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are based on
the location of the group subsidiary which made the sale. The UK region includes the UK-based international activities of Downstream.
All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to Other
businesses and corporate. However, the periodic expense relating to these plans is allocated to the operating segments based upon the business in
which the employees work.
Certain financial information is provided separately for the US as this is an individually material country for bp, and for the UK as this is bp’s country of
domicile.
In February 2020, bp announced plans for a reorganization of the group’s organizational structure. The group’s segmental reporting structure as
described above remained in place throughout 2020. Changes to this structure, as described in Note 1 - Voluntary changes to significant accounting
policies - not yet adopted, came into effect from 1 January 2021.
a Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory and the cost of sales calculated on the first-in first-out (FIFO)
method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of
inventory charged to the income statement is based on its historical cost of purchase or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting
effect on reported income. The amounts disclosed represent the difference between the charge to the income statement for inventory on a FIFO basis (after adjusting for any related movements in net
realizable value provisions) and the charge that would have arisen based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each
operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. The amounts disclosed are not separately
reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.
180
bp Annual Report and Form 20-F 2020
5. Segmental analysis – continued
By business
Upstream
Downstream
Rosneft
Financial statements
Other
businesses
and
corporate
Consolidation
adjustment and
eliminations
$ million
2020
Total
group
Segment revenues
Sales and other operating revenues
Less: sales and other operating revenues between segments
Third party sales and other operating revenues
Earnings from joint ventures and associates – after interest and
tax
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-
retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
US
Non-US
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
34,197
162,974
(17,130)
17,067
(158)
162,816
—
—
—
1,716
(18,521)
180,366
(1,233)
483
18,521
—
—
180,366
(268)
214
(229)
(120)
—
(403)
(21,547)
17
(21,530)
3,418
(2,796)
622
(149)
(89)
(238)
(683)
—
(683)
89
—
89
(18,872)
(2,868)
(21,740)
(3,115)
(33)
(24,888)
3,772
7,447
1,359
1,631
56
1,903
—
—
—
63
617
543
—
—
5,194
9,695
—
2,502
Segment assets
Investments in joint ventures and associates
Additions to non-current assetsb
a See explanation of inventory holding gains and losses on page 180.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
10,749
8,743
3,671
5,359
11,808
—
By business
Upstream
Downstream
Rosneft
1,109
655
—
—
27,337
14,757
Other
businesses and
corporate
Consolidation
adjustment and
eliminations
$ million
2019
Total
group
Segment revenues
Sales and other operating revenues
Less: sales and other operating revenues between segments
Third party sales and other operating revenues
Earnings from joint ventures and associates – after interest and
tax
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-
retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
US
Non-US
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
54,501
(27,034)
250,897
(973)
27,467
249,924
—
—
—
1,788
(782)
1,006
(28,789)
28,789
278,397
—
—
278,397
603
374
2,295
(15)
—
3,257
4,917
(8)
4,909
6,502
685
7,187
2,316
(10)
2,306
(2,771)
—
(2,771)
75
—
75
11,039
667
11,706
(3,489)
(63)
8,154
4,672
9,560
1,335
1,586
118
507
—
—
—
55
572
560
—
—
6,062
11,718
—
1,185
Segment assets
Investments in joint ventures and associates
Additions to non-current assetsb
a See explanation of inventory holding gains and losses on page 180.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
12,196
16,254
3,609
4,014
12,927
—
1,593
2,345
—
—
30,325
22,613
bp Annual Report and Form 20-F 2020
181
5. Segmental analysis – continued
By business
Upstream
Downstream
Rosneft
Other
businesses and
corporate
Consolidation
adjustment and
eliminations
$ million
2018
Total
group
Segment revenues
Sales and other operating revenues
Less: sales and other operating revenues between segments
Third party sales and other operating revenues
Earnings from joint ventures and associates – after interest and
tax
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-
retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
US
Non-US
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
56,399
(28,565)
270,689
(574)
27,834
270,115
—
—
—
1,678
(871)
807
(30,010)
30,010
298,756
—
—
298,756
951
589
2,283
(70)
—
3,753
14,328
(6)
14,322
6,940
(862)
6,078
2,221
67
2,288
(3,521)
—
(3,521)
211
—
211
20,179
(801)
19,378
(2,528)
(127)
16,723
4,211
8,907
900
1,177
—
—
59
203
—
—
5,170
10,287
355
834
—
1,557
—
2,746
Segment assets
Investments in joint ventures and associates
Additions to non-current assetsb c
a See explanation of inventory holding gains and losses on page 180.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
c Amounts have been restated to include acquisitions.
12,785
24,266
2,772
3,609
10,074
—
By geographical area
689
477
—
—
26,320
28,352
US
Non-US
$ million
2020
Total
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Non-current assets
Non-current assetsb c
a Non-US region includes UK $42,729 million
b Non-US region includes UK $19,583 million
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
55,611
124,755
180,366
57
638
695
52,493
108,786
161,279
By geographical area
US
Non-US
$ million
2019
Total
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Non-current assets
Non-current assetsb c
a Non-US region includes UK $63,194 million.
b Non-US region includes UK $22,881 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
89,334
189,063
278,397
315
1,232
1,547
57,757
133,398
191,155
182
bp Annual Report and Form 20-F 2020
5. Segmental analysis – continued
By geographical area
Financial statements
US
Non-US
$ million
2018
Total
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Non-current assets
Non-current assetsb c
a Non-US region includes UK $65,630 million.
b Non-US region includes UK $19,426 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.
98,066
200,690
298,756
369
1,167
1,536
68,188
124,060
192,248
6. Sales and other operating revenues
Crude oil
Oil products
Natural gas, LNG and NGLs
Non-oil products and other revenues from contracts with customers
Revenue from contracts with customers
Other operating revenuesa
Total sales and other operating revenues
a Principally relates to physically settled derivative sales contracts.
2020
5,048
63,564
12,726
9,840
91,178
89,188
180,366
2019
9,141
102,408
18,909
12,169
142,627
135,770
278,397
$ million
2018
10,331
108,515
20,494
12,489
151,829
146,927
298,756
An analysis of third-party sales and other operating revenues by segment and region is provided in Note 5.
The group’s sales to customers of crude oil and oil products were substantially all made by the Downstream segment. The group’s sales to customers
of natural gas, LNG and NGLs were made by the Upstream segment. A significant majority of the group’s sales of non-oil products and other revenues
from contracts with customers were made by the Downstream segment.
Amounts shown for revenue from contracts with customers and other operating revenues for 2018 and 2019 have been represented to align with the
current period. See Note 1 - Other changes to significant accounting policies - Physically settled derivative contracts for further information.
7. Income statement analysis
Interest and other income
Interest income from
Financial assets measured at amortized cost
Financial assets measured at fair value through profit or loss
Other income
Currency exchange losses charged to the income statementa
Expenditure on research and development
Costs relating to the Gulf of Mexico oil spill (pre-interest and tax)b
Finance costs
Interest expense on lease liabilitiesc
Interest expense on other liabilities measured at amortized costd
Capitalized at 2.75% (2019 3.50% and 2018 3.56%)e
Unwinding of discount on provisionsf
Unwinding of discount on other payables measured at amortized cost
a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
b Included within production and manufacturing expenses.
c Interest payable on lease liabilities in 2018 comparative period relates to leases previously classified as finance leases under IAS 17.
d 2020 includes a loss of $158 million associated with the buyback of finance debt.
e Tax relief on capitalized interest is approximately $83 million (2019 $51 million and 2018 $55 million).
f From 1 July 2018, the group changed its method of discounting and unwinding provisions from using real rates to using nominal rates.
2020
2019
215
25
423
663
38
332
255
337
2,166
(345)
437
520
3,115
371
49
349
769
37
364
319
379
2,410
(374)
505
569
3,489
$ million
2018
421
39
313
773
368
429
714
51
2,147
(419)
210
539
2,528
bp Annual Report and Form 20-F 2020
183
8. Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and
evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment.
For information on significant judgements made in relation to oil and natural gas accounting see Intangible assets in Note 1.
2020
2019
$ million
2018
Exploration and evaluation costs
Exploration expenditure written offa
Other exploration costs
Exploration expense for the year
Impairment losses
Intangible assets – exploration and appraisal expenditureb c
Liabilities
Net assets
Cash used in operating activities
Cash used in investing activities
a 2020 includes $2,643 million in the Gulf of Mexico primarily relating to the Paleogene assets, $2,539 million in Canada primarily relating to Terre de Grace, $2,141 million in Brazil, $952 million in Egypt
and $832 million in Angola. 2018 included $447 million in the deepwater Gulf of Mexico principally relating to licence expiries. For further information see Upstream – Exploration on page .
b 2019 includes approximately $2.5 billion relating to Canadian oil sands.
c Amount capitalized at 31 December 2020 relates to assets in various regions. The largest of these is $0.7 billion capitalised in the Middle East region.
9,920
360
10,280
156
4,113
71
4,042
360
674
631
333
964
2
14,091
73
14,018
333
1,215
1,085
360
1,445
137
15,989
60
15,929
360
1,119
9. Taxation
Tax on profit
Current tax
Charge for the year
Adjustment in respect of prior yearsa
Deferred taxb
Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years
2020
2019
2,095
50
2,145
5,316
(68)
5,248
$ million
2018
6,217
(221)
5,996
(7,826)
1,522
(6,304)
(4,159)
(1,190)
(94)
(1,284)
3,964
907
242
1,149
7,145
Tax charge (credit) on profit or loss
a The adjustments in respect of prior years reflect the reassessment of the current tax balances for prior years in light of changes in facts and circumstances during the year.
b Origination and reversal of temporary differences in the current year include the impact of tax rate changes on deferred tax balances. The adjustments in respect of prior years reflect the reassessment
of deferred tax balances for prior periods in light of all other changes in facts and circumstances during the year; 2020 includes charges for the reassessment of deferred tax asset recognition in light of
revisions to price assumptions.
In 2020, the total tax charge recognized within other comprehensive income was $39 million (2019 $227 million charge and 2018 $714 million charge),
primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit liability or asset. See Note 32
for further information.
The total tax charge recognized directly in equity was $154 million (2019 $37 million charge and 2018 $17 million charge). 2020 principally relates to a
non-controlling interest transaction entered into by Rosneft.
Reconciliation of the effective tax rate
The following table provides a reconciliation of the group weighted average statutory corporate income tax rate to the effective tax rate of the group on
profit or loss before taxation.
184
bp Annual Report and Form 20-F 2020
9. Taxation – continued
Profit (loss) before taxation
Tax charge (credit) on profit or loss
Effective tax rate
Tax rate computed at the weighted average statutory ratea
Increase (decrease) resulting from
Tax reported in equity-accounted entities
Adjustments in respect of prior years
Deferred tax not recognized
Tax incentives for investment
Foreign exchange
Items not deductible for tax purposes
Other
Financial statements
2020
(24,888)
(4,159)
17%
2019
8,154
3,964
49%
$ million
2018
16,723
7,145
43%
31
52
—
(6)
(3)
1
(1)
(3)
(2)
17
(7)
(2)
(2)
(3)
1
4
6
49
%
43
(5)
—
1
(2)
3
1
2
43
Effective tax rate
a Calculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries.
Deferred tax
Analysis of movements during the year in the net deferred tax (asset) liability
At 31 December
Adjustment on adoption of IFRS 16
At 1 January
Exchange adjustments
Credit for the year in the income statement
Charge for the year in other comprehensive income
Charge for the year in equity
Acquisitions and disposals
At 31 December
2020
5,190
—
5,190
55
(6,304)
48
154
(56)
(913)
$ million
2019
6,106
(75)
6,031
72
(1,284)
233
37
101
5,190
The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference:
Deferred tax liability
Depreciation
Pension plan surpluses
Derivative financial instruments
Other taxable temporary differences
Deferred tax asset
Depreciation
Lease liabilities
Pension plan and other post-retirement benefit plan deficits
Decommissioning, environmental and other provisions
Derivative financial instruments
Tax credits
Loss carry forward
Other deductible temporary differences
Net deferred tax charge (credit) and net deferred tax (asset) liabilityb
Of which – deferred tax liabilities
– deferred tax assets
Income statementa
$ million
Balance sheet
2020
2019
2018
2020
2019
(7,295)
69
33
(32)
(7,225)
(849)
286
2
438
—
310
543
191
921
(6,304)
(1,436)
(31)
29
159
(1,279)
—
264
62
(472)
63
(336)
12
402
(5)
(1,284)
(1,297)
65
(36)
(57)
(1,325)
—
8
(6)
1,505
(31)
123
559
316
2,474
1,149
15,361
2,691
63
1,562
19,677
(849)
(1,122)
(1,548)
(7,155)
(25)
(3,652)
(5,319)
(920)
(20,590)
(913)
6,831
7,744
22,627
2,290
29
1,496
26,442
—
(1,380)
(1,367)
(7,579)
(24)
(3,964)
(5,834)
(1,104)
(21,252)
5,190
9,750
4,560
a The 2018 income statement is impacted by the reduction in US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018.
b Included within the net deferred tax (asset) liability is a deferred tax asset balance of $5,471 million (2019 $5,526 million) related to the Gulf of Mexico oil spill.
bp Annual Report and Form 20-F 2020
185
9. Taxation – continued
Of the $7,744 million of deferred tax assets recognised on the group balance sheet at 31 December 2020 (2019 $4,560 million), $7,659 million (2019
$2,421 million) relates to entities that have suffered a loss in either the current or preceding period. This amount is supported by forecasts that indicate
sufficient future taxable profits will be available to utilize such assets. For 2020, $3,906 million relates to the US, $707 million relates to India, $637
million relates to Australia and $588 million relates to Trinidad & Tobago (2019 $2,421 million relates to the US).
A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the table
below.
$ billion
At 31 December
Unused US state tax lossesa
Unused tax losses – other jurisdictionsb
Unused tax credits
2020
2.4
6.0
26.9
23.0
3.9
46.1
0.8
2019
2.3
3.5
25.4
21.5
3.9
40.4
1.5
of which – arising in the UKc
– arising in the USd
Deductible temporary differencese
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities
a For 2020 these losses expire in the period 2021-2040 with applicable tax rates ranging from 3% to 10%.
b The majority of the unused tax losses have no fixed expiry date.
c The UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. No deferred tax asset has been
recognized on these tax credits as they are unlikely to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief in respect of overseas tax. These tax
credits have no fixed expiry date.
d For 2020 the US unused tax credits expire in the period 2021-2030.
e The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date.
Impact of previously unrecognized deferred tax or write-down of deferred tax assets on tax charge
Current tax benefit relating to the utilization of previously unrecognized deferred tax assets
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets
Deferred tax benefit relating to the recognition of previously unrecognized deferred tax assets
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset
2020
46
11
—
1,622
2019
272
96
364
73
$ million
2018
83
—
112
169
10. Dividends
The quarterly dividend which is expected to be paid on 26 March 2021 in respect of the fourth quarter 2020 is 5.25 cents per ordinary share ($0.315 per
American Depositary Share (ADS)). The corresponding amount in sterling was announced on 15 March 2021.
Dividends announced and paid in cash
Preference shares
Ordinary shares
March
June
September
December
Dividend announced, paid in March 2021
Pence per share
Cents per share
2020
2019
2018
2020
2019
2018
2020
2019
$ million
2018
8.1558 7.7382 7.1691
8.3421 8.0655 7.4435
4.0433 8.3475 7.9296
3.9169 7.8250 8.0251
24.4581 31.9762 30.5673
10.25
10.25
10.25
10.25
41.00
10.00
10.00
10.25
10.25
40.50
10.50
10.50
5.25
5.25
31.50
5.25
1
1
1
1,435
1,779
1,656
2,075
6,946
1,828
1,727
1,409
1,734
6,699
2,102
2,119
1,059
1,059
6,340
1,067
The amount of unclaimed dividends recognised as a liability at 31 December 2020 is $50 million (2019 $22 million).
The details of the scrip dividends issued are shown in the table below. The board decided not to offer a scrip dividend alternative in respect of any
dividends announced since the third quarter 2019, including the fourth quarter 2020 dividend expected to be paid on 26 March 2021.
Number of shares issued (thousand)
Value of shares issued ($ million)
2020
2019
2018
— 208,927 195,305
1,381
1,387
—
The financial statements for the year ended 31 December 2020 do not reflect the dividend announced on 2 February 2021 and paid in March 2021; this
will be treated as an appropriation of profit in the year ending 31 December 2021.
186
bp Annual Report and Form 20-F 2020
11. Earnings per share
Per ordinary share
Basic earnings per share
Diluted earnings per share
Per American Depositary Share (ADS)
Basic earnings per share
Diluted earnings per share
Financial statements
2020
(100.42)
(100.42)
2020
(6.03)
(6.03)
2019
19.84
19.73
2019
1.19
1.18
Cents per share
2018
46.98
46.67
Dollars per share
2018
2.82
2.80
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to bp ordinary shareholders by the weighted
average number of ordinary shares outstanding during the year.
The weighted average number of shares outstanding includes certain shares that will be issuable in the future under employee share-based payment
plans and excludes treasury shares, which includes shares held by the Employee Share Ownership Plan trusts (ESOPs).
For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average number
of shares that are potentially issuable in connection with employee share-based payment plans. If the inclusion of potentially issuable shares would
decrease loss per share, the potentially issuable shares are excluded from the weighted average number of shares outstanding used to calculate
diluted earnings per share.
Profit attributable to bp shareholders
Less: dividend requirements on preference shares
Profit for the year attributable to bp ordinary shareholders
Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans
Weighted average number of ordinary shares outstanding used to calculate diluted
earnings per share
Basic weighted average number of ordinary shares – ADS equivalent
Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee share-based
payment plans
Weighted average number of ordinary shares (ADS equivalent) outstanding used to
calculate diluted earnings per share
2020
(20,305)
1
(20,306)
2019
4,026
1
4,025
$ million
2018
9,383
1
9,382
2020
2019
20,221,514
20,284,859
Shares thousand
2018
19,970,215
—
114,811
132,278
20,221,514
20,399,670
20,102,493
2020
2019
3,370,252
3,380,809
Shares thousand
2018
3,328,369
—
19,136
22,046
3,370,252
3,399,945
3,350,415
The number of ordinary shares outstanding at 31 December 2020, excluding treasury shares, and including certain shares that will be issuable in the
future under employee share-based payment plans was 20,264,027,711. Between 31 December 2020 and 25 February 2021, the latest practicable date
before the completion of these financial statements, there was a net increase of 66,249,231 in the number of ordinary shares outstanding primarily as a
result of share issues in relation to employee share-based payment plans.
Employee share-based payment plans
The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information
on these plans for directors is shown in the Directors remuneration report on pages 103-126.
The following table shows the number of shares potentially issuable under equity-settled employee share option plans, including the number of options
outstanding, the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The dilutive effect of
these plans at 31 December is also shown.
Share options
Number of optionsa b
thousand
28,171
1,874
2,497
2020
Weighted average
exercise price $
2019
Number of optionsa b
thousand
17,112
1,067
3,990
Weighted average
exercise price $
4.91
3.97
n/a
Outstanding
Exercisable
Dilutive effect
a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2020 the quoted market price of one bp ordinary share was £2.55 (2019 £4.72).
In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior leaders and
certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends
which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements
apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee share plans are
shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown.
3.79
5.02
n/a
bp Annual Report and Form 20-F 2020
187
11. Earnings per share – continued
Share plans
Vesting
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
Over 4 years
2020
2019
Number of sharesa
Number of sharesa
thousand
87,517
85,720
147,097
749
349
321,432
104,068
thousand
91,105
89,939
80,844
725
576
263,189
92,343
Dilutive effect
a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net decrease of 29,718,486 in the number of potential ordinary shares relating to employee share-based payment plans between
31 December 2020 and 25 February 2021.
188
bp Annual Report and Form 20-F 2020
12. Property, plant and equipment (PP&E)
Financial statements
Land and land
improvements Buildings
Oil and gas
propertiesa
Plant,
machinery
and
equipment
Fittings,
fixtures and
office
equipment
Transportation
Oil depots,
storage tanks
and service
stations
$ million
Total
Cost - owned PP&E
At 1 January 2020
Exchange adjustments
Additions
Acquisitions
Transfers from intangible assets
Reclassified as assets held for sale
Deletions
At 31 December 2020
Depreciation - owned PP&E
At 1 January 2020
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Reclassified as assets held for sale
Deletions
At 31 December 2020
Owned PP&E - net book amount at 31 December
2020
Right-of-use assets - net book amount at 31
December 2020b
Total PP&E - net book amount at 31 December
2020
Cost - owned PP&E
At 1 January 2019
Exchange adjustments
Additions
Acquisitions
Transfers from intangible assets
Reclassified as assets held for sale
Deletions
At 31 December 2019
Depreciation - owned PP&E
At 1 January 2019
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Reclassified as assets held for sale
Deletions
At 31 December 2019
Owned PP&E - net book amount at 31 December
2019
Right-of-use assets - net book amount at 31
December 2019b
Total PP&E - net book amount at 31 December
2019
Assets under construction included above
At 31 December 2020
At 31 December 2019
Depreciation charge for the year on right-of-use assets
219
101
3,609 1,422 214,352 46,724
801
1,539
35
—
—
(6,185)
(146)
3,872 1,210 214,323 42,914
6
63
89 —
— —
— —
(281)
—
6,922
—
605
(1,425)
(6,131)
6
697 124,766 21,527
581
424
—
35
1,312
46 10,068
113
744
9 11,705
8
—
(83)
—
(1)
(326)
— —
—
(3,976)
(5,579)
(126)
(45)
631 140,551 20,031
692
2,532
33
586
5
—
—
(738)
2,418
2,006
26
170
2
—
—
(359)
1,845
3,474
8
49
9
—
—
(491)
3,049
2,744
9
77
4
(5)
—
(448)
2,381
8,694 280,807
1,670
10,124
514
605
(1,425)
(14,233)
10,276 278,062
603
864
376
—
—
(261)
4,865 157,186
379
879
740
12,526
3
12,475
—
(89)
—
(326)
(10,734)
(201)
5,786 171,917
3,180
579 73,772 22,883
573
668
4,490 106,145
— 1,254
77
792
21
2,855
3,692
8,691
3,180 1,833 73,849 23,675
594
3,523
8,182 114,836
5
3,562 1,502 232,684 45,721
(158)
—
(22)
2,433
93 13,237
88
—
—
51 —
—
1,885
— —
—
(26) — (22,602)
(1,272)
(178) (10,852)
(44)
3,609 1,422 214,352 46,724
5
697 133,687 20,512
626
(63)
—
(4)
1,705
59 13,012
44
64
5,871
1
1
—
(129)
— —
—
— — (17,764)
(65)
(86)
(691)
(9,911)
697 124,766 21,527
581
2,747
15
172
—
—
(76)
(326)
2,532
2,041
12
168
1
—
(69)
(147)
2,006
10,183
(3)
274
—
—
(6,708)
(272)
3,474
7,819
(3)
173
404
(2)
(5,478)
(169)
2,744
8,866 305,265
(232)
16,941
59
1,885
(29,412)
(13,699)
8,694 280,807
(69)
644
8
—
—
(755)
5,146 170,528
(98)
15,581
6,346
(131)
(23,311)
(11,729)
4,865 157,186
(45)
420
4
—
—
(660)
3,028
725 89,586 25,197
526
730
3,829 123,621
— 1,196
128
1,241
16
3,385
3,055
9,021
3,028 1,921 89,714 26,438
542
4,115
6,884 132,642
17,259
23,897
2020
2019
a For information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1.
b $284 million (2019 $653 million) of drilling rig right-of-use assets and $2,521 million (2019 $2,929 million) of shipping vessel right-of-use assets are included in Plant, machinery and equipment and
192
220
829
784
579
526
637
671
43
31
10
9
2,290
2,241
Transportation respectively.
bp Annual Report and Form 20-F 2020
189
13. Capital commitments
Authorized future capital expenditure for property, plant and equipment (excluding right-of-use assets) by group companies for which contracts had
been signed at 31 December 2020 amounted to $8,009 million (2019 $11,382 million, 2018 $8,319 million). bp has contracted capital commitments
amounting to $1,087 million (2019 $77 million, 2018 $25 million) in relation to joint ventures and $183 million (2019 $787 million, 2018 $1,227 million) in
relation to associates. bp’s share of contracted capital commitments of joint ventures amounted to $900 million (2019 $1,024 million, 2018 $619
million).
14. Goodwill and impairment review of goodwill
Cost
At 1 January
Exchange adjustments
Acquisitions and other additionsa
Reclassified as assets held for sale
Deletions
At 31 December
Impairment losses
At 1 January
Exchange adjustments
Impairment losses for the year
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
a 2020 principally relates to an acquisition in the US Fuels business.
Impairment review of goodwill
Goodwill at 31 December
Upstream
Downstream
Other businesses and corporate
2020
12,865
184
632
(199)
(389)
13,093
997
1
1
(386)
613
12,480
11,868
2020
7,765
4,660
55
12,480
$ million
2019
12,815
79
26
—
(55)
12,865
611
—
386
—
997
11,868
12,204
$ million
2019
7,958
3,904
6
11,868
Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the synergies
of the acquisition. For Upstream, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For Downstream, goodwill has been
allocated to Lubricants, US Fuels, European Fuels and Other.
For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangible
assets and goodwill in Note 1.
Upstream
Goodwill
Excess of recoverable amount over carrying amount
2020
7,765
31,749
$ million
2019
7,958
93,250
The table above shows the carrying amount of goodwill for the segment at the period end and the excess of the recoverable amount, based on a pre-
tax value-in-use calculation, over the carrying amount (headroom) at the date of the most recent test. The reduction in headroom since the prior period
principally relates to the impact of changes to price assumptions.
No impairment of the Upstream goodwill balance was recognized during 2020 (2019 $386 million).
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of
cessation of production of each producing field, based on current estimates of reserves and resources, appropriately risked. Midstream and supply and
trading activities and equity-accounted entities are generally not included in the impairment review of goodwill, as they do not represent part of the
grouping of cash-generating units to which the goodwill relates and which is used to monitor the goodwill for internal management purposes. Where
such activities form part of a wider Upstream cash-generating unit, they are reflected in the test. As the production profile and related cash flows can
be estimated from bp’s past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis
upon which to assess goodwill and individual assets for impairment. The estimated date of cessation of production depends on the interaction of a
number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the
infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession and the selling price of
the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of each field is
computed using appropriate individual economic models and key assumptions agreed by bp management.
Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital
expenditure, are derived from the business segment plan. The production profiles used are consistent with the reserve and resource volumes approved
as part of bp’s centrally controlled process for the estimation of proved and probable reserves and total resources. Oil and gas price assumptions and
discount rate assumptions used were as disclosed in Note 1. The average production for the purposes of goodwill impairment testing over the next 15
years is 877 mmboe per year (2019 829 mmboe per year). The weighted average pre-tax discount rate used in the test is 11% (2019 12%).
190
bp Annual Report and Form 20-F 2020
Financial statements
14. Goodwill and impairment review of goodwill – continued
The most recent review for impairment was carried out in the fourth quarter. The key assumptions used in the value-in-use calculation are oil and
natural gas prices, production volumes and the discount rate. The value-in-use calculation has been prepared solely for the purposes of determining
whether the goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of
the test. The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are
subject to revision as further technical information becomes available and economic conditions change. Due to economic developments, regulatory
change and emissions reduction activity arising from climate concern and other factors, future commodity prices and other assumptions may differ
from the forecasts used in the calculations.
Sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price or production
sensitivities do not fully reflect the specific impacts for each contractual arrangement and will not capture all favourable impacts that may arise from
cost deflation or savings. A detailed calculation at any given price or production profile may, therefore, produce a different result.
Adverse changes in input assumptions applied in respect to assets carried at or close to their value in use, primarily being those assets previously
impaired, would have a limited effect on goodwill headroom, instead resulting in a direct impairment of the particular cash-generating unit's net book
value. Conversely, a reduction in the value in use of those assets carried at a value below their respective values in use would result in an adverse
impact on the goodwill headroom. It is estimated that a 21% reduction in revenue throughout each year of the remaining life of those assets, either as
a result of adverse price or production conditions or a combination of each, would cause the recoverable amount to be equal to the carrying amount of
goodwill and related net non-current assets of the segment.
It is estimated that no reasonably possible change in the discount rate would cause the recoverable amount to be equal to the carrying amount of
goodwill and related net non-current assets of the segment.
Downstream
Goodwill
Lubricants
US Fuels
2,865
606
European
Fuels
913
Other
276
Total
4,660
Lubricants
US Fuels
2,779
—
European
Fuels
858
Other
267
Total
3,904
2020
$ million
2019
Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to five years. To determine the value
in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value.
Lubricants
As permitted by IAS 36, the detailed calculations of Lubricants’ recoverable amount performed in the most recent detailed calculation in 2018 was used
as the basis for the tests in 2020 as the criteria of IAS 36 were considered satisfied: the headroom was substantial in 2018; there have been no
significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount is remote.
The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and
discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the
assumptions used in the Lubricants unit’s business plan and values assigned to these key assumptions reflect past experience. No reasonably possible
change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the plan period
are extrapolated using a nominal 2.8% growth rate.
15. Intangible assets
Cost
At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers to property, plant and equipment
Reclassified as assets held for sale
Deletions
At 31 December
Amortization
At 1 January
Exchange adjustments
Exploration expenditure written off
Charge for the year
Impairment losses
Reclassified as assets held for sale
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
a For further information see Intangible assets within Note 1 and Note 8.
Exploration
and appraisal
expenditurea
Other
intangibles
15,306
—
—
703
(605)
—
(987)
14,417
1,215
—
9,920
—
156
—
(987)
10,304
4,113
14,091
4,900
138
318
645
—
—
(379)
5,622
3,452
93
—
372
9
—
(284)
3,642
1,980
1,448
2020
Total
20,206
138
318
1,348
(605)
—
(1,366)
20,039
4,667
93
9,920
372
165
—
(1,271)
13,946
6,093
15,539
Exploration and
appraisal
expenditurea
Other
intangibles
17,053
—
—
1,268
(1,885)
(671)
(459)
15,306
1,064
—
631
—
2
(61)
(421)
1,215
14,091
15,989
4,504
2
35
457
—
—
(98)
4,900
3,209
4
—
331
2
—
(94)
3,452
1,448
1,295
$ million
2019
Total
21,557
2
35
1,725
(1,885)
(671)
(557)
20,206
4,273
4
631
331
4
(61)
(515)
4,667
15,539
17,284
bp Annual Report and Form 20-F 2020
191
16. Investments in joint ventures
The following table provides aggregated summarized financial information relating to the group’s share of joint ventures.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Non-controlling interest
Profit for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Less: non-controlling interests
Group investment in joint ventures
Group share of net assets (as above)
Loans made by group companies to joint ventures
a 2019 has been restated to include non-controlling interest
2020
10,545
(151)
201
(352)
(51)
1
(302)
(5)
(307)
12,646
3,424
16,070
2,644
5,023
7,667
8,403
39
8,364
2019a
14,139
976
109
867
289
2
576
(6)
570
13,457
3,738
17,195
2,514
4,676
7,190
10,005
49
9,956
8,364
(2)
8,362
9,956
35
9,991
Transactions between the group and its joint ventures are summarized below.
Sales to joint ventures
Product
LNG, crude oil and oil products, natural gas
2020
Amount
receivable at
31 December
180
Sales
2,974
2019
Amount
receivable at
31 December
431
Sales
4,884
Sales
4,603
Purchases from joint ventures
Product
2020
Amount
payable at
31 December
2019
Amount
payable at
31 December
Purchases
Purchases
Purchases
$ million
2018
13,258
1,396
85
1,311
414
—
897
6
903
$ million
2018
Amount
receivable at
31 December
251
$ million
2018
Amount
payable at
31 December
LNG, crude oil and oil products, natural gas, refinery operating
costs, plant processing fees
959
84
1,812
225
1,336
300
The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in
cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in
respect of bad or doubtful debts. Dividends receivable are not included in the table above.
bp's share of impairment charges taken by joint ventures in 2020 was $433 million (2019 $25 million reversal) of which $336 million (2019 $25 million
reversal) was in the Upstream segment.
17. Investments in associates
The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in the
group income statement and on the group balance sheet.
Rosneft
Other associates
Income statement
Earnings from associates
- after interest and tax
$ million
Balance sheet
Investments in
associates
2020
(229)
128
(101)
2019
2,295
386
2,681
2018
2,283
573
2,856
2020
11,808
7,167
18,975
2019
12,927
7,407
20,334
The associate that is material to the group at both 31 December 2020 and 2019 is Rosneft.
192
bp Annual Report and Form 20-F 2020
Financial statements
17. Investments in associates – continued
bp owns 19.75% of the voting shares of Rosneft which are listed on the MICEX stock exchange in Moscow and its global depository receipts are listed
on the London Stock Exchange. Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is wholly owned by the Russian government.
At 31 December 2020, Rosneftegaz held 40.4% (2019 50.0% plus one share) of the voting shares of Rosneft.
bp classifies its investment in Rosneft as an associate because, in management’s judgement, bp has significant influence over Rosneft; see Interests in
other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional currency is the Russian
rouble. The decrease in the group's equity-accounted investment balance for Rosneft at 31 December 2020 compared with 31 December 2019
principally relates to adverse foreign exchange effects, which have been recognized in other comprehensive income, and dividends, partially offset by
bp's share of Rosneft’s changes in equity.
During 2020 Rosneft completed a transaction to transfer all of its interest and cease participation in its Venezuelan businesses to a company owned by
the government of the Russian Federation. In consideration, Rosneft received shares equal to a 9.6% share of its own equity. The shares are held by a
100% subsidiary of Rosneft and accounted for as treasury shares. Rosneft also entered into share buyback transactions during the year. These are also
accounted for as treasury shares. bp retains 19.75% of the voting rights at meetings of Rosneft shareholders and will continue to be entitled to
dividends based on its current shareholding. bp’s economic interest, however, increased as a result of its indirect interest in the shares held by the
subsidiary of Rosneft. bp’s share of profit or loss of Rosneft reflects its economic interest. At 31 December 2020, bp's economic interest was 22.03%.
On 28 December 2020 Rosneft completed the acquisition of 100% stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the sale of a 10%
interest in LLC Vostok Oil. A preliminary assessment of the fair values of the assets and liabilities acquired and the consideration transferred in respect
of the acquisitions has been undertaken and the further impact, if any, on bp’s accounting for its equity-accounted investment in Rosneft will be
updated once this has been finalised.
The value of bp’s 19.75% shareholding in Rosneft based on the quoted market share price of $5.64 per share (2019 $7.21 per share) was
$11,804 million at 31 December 2020 (2019 $15,090 million). The value of bp's 22.03% economic interest based on the quoted market share price was
$13,167 million at 31 December 2020.
The following table provides summarized financial information relating to Rosneft. This information is presented on a 100% basis and reflects
adjustments made by bp to Rosneft’s own results in applying the equity method of accounting. bp adjusts Rosneft’s results for the accounting required
under IFRS relating to bp’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal of bp’s interest in TNK-
BP.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit (loss) before taxation
Taxation
Non-controlling interests
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Less: non-controlling interests
$ million
Gross amount
2018
131,322
18,886
2,785
16,101
2,957
1,585
11,559
2,086
13,645
2020
82,786
1,270
1,742
(472)
208
482
(1,162)
1,653
491
175,978
42,459
218,437
49,781
96,727
146,508
71,929
10,897
61,032
2019
134,046
17,473
1,281
16,192
3,058
1,514
11,620
572
12,192
161,327
38,657
199,984
44,459
79,327
123,786
76,198
10,744
65,454
The group received dividends, net of withholding tax, of $480 million from Rosneft in 2020 (2019 $785 million and 2018 $620 million).
bp Annual Report and Form 20-F 2020
193
17. Investments in associates – continued
Summarized financial information for the group’s share of associates is shown below.
2020
2019
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit (loss) before taxation
Taxation
Non-controlling interests
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Less: non-controlling interests
Group investment in associates
Group share of net assets (as above)
Loans made by group companies to
associates
Rosnefta
17,535
295
372
(77)
51
101
(229)
336
107
Rosnefta
Other
Total
5,946 23,481 26,474
3,451
571
253
452
3,198
119
604
118
102
299
2,295
(101)
317
113
2,408
216
276
80
196
67
1
128
(19)
109
Rosnefta
Other
Total
7,934 34,408 25,936
3,730
4,239
550
340
3,180
3,899
584
919
313
299
2,283
2,681
412
88
2,695
2,769
788
87
701
315
—
386
(25)
361
1,924
7,635
8,238
1,749
9,987
33,754 11,449 45,203 31,862 11,504 43,366
9,559
41,992 13,198 55,190 39,497 13,428 52,925
1,908 10,689
4,577 20,244
6,485 30,933
6,943 21,992
2,122
6,943 19,870
1,346 10,881
8,781
4,709 23,267 15,667
6,055 34,148 24,448
7,143 21,042 15,049
2,122
2,091
7,143 18,951 12,927
9,535
18,558
28,093
13,899
2,091
11,808
—
—
11,808
7,143 18,951 12,927
6,943 19,870
—
11,808
24
—
7,167 18,975 12,927
24
464
464
7,407 20,334
$ million
bp share
2018
Other
Total
9,134 35,070
4,880
1,150
628
78
4,252
1,072
1,083
499
—
313
2,856
573
(1)
411
3,267
572
a In 2014-2019, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars. Foreign exchange gains and losses arising on the
retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments were recognized initially in other comprehensive income, and were
reclassified to the income statement as the hedged revenue was recognized.
During the year, bp and Reliance Industries completed the formation of a new fuels and mobility venture, Reliance BP Mobility Limited, that will operate
across India under the Jio-bp brand. bp invested $1 billion to acquire a 49% stake in the company.
Transactions between the group and its associates are summarized below.
Sales to associates
Product
LNG, crude oil and oil products, natural gas
2020
Amount
receivable at
31 December
169
Sales
855
2019
Amount
receivable at
31 December
243
Sales
1,544
Sales
2,064
Purchases from associates
Product
2020
Amount
payable at
31 December
2019
Amount
payable at
31 December
Purchases
Purchases
Crude oil and oil products, natural gas, transportation tariff
4,926
1,280
9,503
1,641
Purchases
14,112
$ million
2018
Amount
receivable at
31 December
393
$ million
2018
Amount
payable at
31 December
2,069
In addition to the transactions shown in the table above, in 2018 bp acquired a 49% stake in LLC Kharampurneftegaz, a Rosneft subsidiary, which
develops resources within the Kharampurskoe and Festivalnoye licence areas in Yamalo-Nenets in northern Russia. bp’s interest in LLC
Kharampurneftegaz is accounted for as an associate.
The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash.
There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in
respect of bad or doubtful debts. Dividends receivable are not included in the table above.
The majority of purchases from associates relate to crude oil and oil products transactions with Rosneft. Sales to associates are related to various
entities.
bp has commitments amounting to $10,777 million (2019 $11,198 million), primarily in relation to contracts with its associates for the purchase of
transportation capacity. For information on capital commitments in relation to associates see Note 13.
bp's share of impairment charges taken by associates in 2020 was $414 million (2019 $152 million).
194
bp Annual Report and Form 20-F 2020
18. Other investments
Equity investmentsa
Contingent consideration
Other
Financial statements
Current
Non-current
Current
2020
—
317
16
333
913
1,682
151
2,746
—
122
47
169
$ million
2019
Non-current
571
476
229
1,276
a Approximately half of the group's equity investments are unlisted.
Contingent consideration relates to amounts arising on disposals which are financial assets classified as measured at fair value through profit or loss.
The fair value is determined using an estimate of discounted future cash flows that are expected to be received and is considered a level 3 valuation
under the fair value hierarchy. Future cash flows are estimated based on inputs including oil and natural gas prices, production volumes and operating
costs related to the disposed operations. The discount rate used is based on a risk-free rate adjusted for asset-specific risks. The contingent
consideration principally relates to the disposal of our Alaskan business.
19. Inventories
Crude oil
Natural gas
Emissions allowancesa
Refined petroleum and petrochemical products
Trading inventories
Supplies
2020
4,498
265
1,297
8,791
14,851
292
15,143
1,730
16,873
132,104
$ million
2019
5,610
222
1,193
11,714
18,739
182
18,921
1,959
20,880
209,672
Cost of inventories expensed in the income statement
a Comparative period has been re-presented to align with the current period.
The inventory valuation at 31 December 2020 is stated net of a provision of $584 million (2019 $650 million) to write down inventories to their net
realizable value, of which $216 million (2019 $290 million) relates to hydrocarbon inventories. The net credit to the income statement in the year in
respect of inventory net realizable value provisions was $17 million (2019 $348 million credit), of which $71 million credit (2019 $309 million credit)
related to hydrocarbon inventories.
Trading inventories are valued using quoted benchmark prices adjusted as appropriate for location and quality differentials. They are predominantly
categorized within level 2 of the fair value hierarchy.
20. Trade and other receivables
Financial assets
Trade receivables
Amounts receivable from joint ventures and associates
Receivables related to disposalsa
Other receivables
Non-financial assets
Gulf of Mexico oil spill trust fund reimbursement asset
Sales taxes and production taxes
Other receivables
2020
$ million
2019
Current
Non-current
Current
Non-current
12,926
339
1,291
2,628
17,184
32
557
175
764
17,948
19
10
2,402
637
3,068
—
504
779
1,283
4,351
19,424
672
159
3,166
23,421
201
640
180
1,021
24,442
22
2
125
701
850
—
538
759
1,297
2,147
a For further information see Note 4 - Disposals and Impairment.
In both 2020 and 2019 the group entered into non-recourse arrangements to discount certain receivables in support of supply and trading activities and
the management of credit risk.
Trade and other receivables, other than certain receivables related to disposals, are predominantly non-interest bearing. See Note 29 for further
information.
bp Annual Report and Form 20-F 2020
195
21. Valuation and qualifying accounts
2020
2019
$ million
2018
Trade and
other
receivables
Fixed asset
investments
Trade and
other
receivables
Fixed asset
investments
Trade and
other
receivables
Fixed asset
investments
314
416
509
At 1 January – IAS 39
Adjustment on adoption of IFRS 9
At 1 January – IFRS 9
Charged to costs and expenses
Charged to other accountsa
Deductions
At 31 December
a Principally exchange adjustments.
Valuation and qualifying accounts relating to trade and other receivables comprise expected credit loss allowances. The adjustment on adoption of IFRS
9 relates to the additional loss allowance required by IFRS 9's expected credit loss model. The expected credit loss allowance comprises $456 million
(2019 $414 million, 2018 $327 million) relating to receivables that were credit-impaired at the end of the year and $99 million (2019 $95 million, 2018
$89 million) relating to receivables that were not credit-impaired at the end of the year. Whilst credit risk has increased since 31 December 2019, there
has also been a significant reduction in the group's trade and other receivables balance. Therefore, the total expected credit loss allowances recognized
as at 31 December 2020 have not significantly increased during the year.
—
509
214
2
(170)
555
—
416
206
(2)
(111)
509
—
235
28
—
(14)
249
115
450
30
(12)
(52)
416
249
—
249
103
—
(166)
186
(85)
229
10
(1)
(3)
235
235
335
Valuation and qualifying accounts relating to fixed asset investments comprise impairment provisions for investments in equity-accounted entities. The
adjustment on adoption of IFRS 9 primarily relates to amounts provided against investments in equity instruments that were held at cost less
impairment losses under IAS 39 but that are classified as measured at fair value through profit or loss under IFRS 9.
In addition to the amounts presented above, expected loss allowances on cash and cash equivalents classified as measured at amortized cost totalled
$11 million (2019 $11 million). For further information on the group's credit risk management policies and how the group recognizes and measures
expected losses see Note 29.
Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply.
22. Trade and other payables
Financial liabilities
Trade payables
Amounts payable to joint ventures and associates
Payables for capital expenditure and acquisitions
Payables related to the Gulf of Mexico oil spill
Other payables
Non-financial liabilities
Sales taxes, customs duties, production taxes and social security
Other payables
2020
$ million
2019
Current
Non-current
Current
Non-current
23,157
1,364
2,297
1,399
5,041
33,258
2,103
653
2,756
36,014
—
—
1,033
9,988
681
11,702
73
337
410
12,112
30,538
1,866
3,868
1,617
5,810
43,699
2,381
749
3,130
46,829
—
—
1,196
10,863
133
12,192
33
401
434
12,626
Materially all of bp's trade payables have payment terms in the range of 30 to 60 days and give rise to operating cash flows.
Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 29 (c) for further
information.
Payables related to the Gulf of Mexico oil spill include amounts payable under the 2016 consent decree and settlement agreement with the United
States and five Gulf coast states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a
discounted basis the amounts included in payables related to the Gulf of Mexico oil spill for these elements of the agreements are $4,837 million
payable over 12 years, $2,584 million payable over 13 years and $3,549 million payable over 12 years respectively at 31 December 2020. Reported
within net cash provided by operating activities in the group cash flow statement is a net cash outflow of $1,786 million (2019 outflow of $2,694 million,
2018 outflow of $3,531 million) related to the Gulf of Mexico oil spill, which includes payments made in relation to these agreements. For 2018
payments under the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident are also included. For full
details of these agreements, see bp Annual Report and Form 20-F 2015 - Legal Proceedings.
Payables related to the Gulf of Mexico oil spill at 31 December 2020 also include amounts payable for settled economic loss and property damage
claims which are payable over a period of up to seven years.
196
bp Annual Report and Form 20-F 2020
23. Provisions
At 1 January 2020
Exchange adjustments
Increase (decrease) in existing provisions
Write-back of unused provisions
Unwinding of discount
Utilization
Reclassified to other payables
Reclassified as liabilities directly associated with
assets held for sale
Deletions
At 31 December 2020
Of which – current
– non-current
Decommissioning
Environmental
15,110
96
(686)
(11)
369
(7)
(245)
(10)
(140)
14,476
428
14,048
1,620
9
297
(88)
39
(246)
—
—
(2)
1,629
273
1,356
Litigation and
claims
1,281
1
260
(12)
18
(508)
(129)
—
(1)
910
260
650
Emissions
919
25
1,429
(17)
—
(687)
—
—
—
1,669
1,621
48
Financial statements
$ million
Total
20,951
215
2,274
(469)
437
(1,826)
(460)
(10)
(151)
20,961
3,761
17,200
Other
2,021
84
974
(341)
11
(378)
(86)
—
(8)
2,277
1,179
1,098
The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The
environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution relating to
soil, groundwater, surface water and sediment contamination. The litigation and claims category includes provisions for matters related to, for example,
commercial disputes, product liability, and allegations of exposures of third parties to toxic substances. The emissions provision relates to the group’s
obligation to transfer emissions allowances under relevant regulations. The provision will principally be settled through allowances already held as
inventory in the group balance sheet. Included within the other category at 31 December 2020 are reinvent bp restructuring provisions for employee
termination payments of $428 million.
For information on significant estimates and judgements made in relation to provisions, see Provisions and contingencies within Note 1.
Gulf of Mexico oil spill
The group has recognized certain assets, payables and provisions and incurs certain residual costs relating to the Gulf of Mexico oil spill that occurred in
2010. In addition to the Litigation and claims narrative provided in this note, for further information see Notes 7, 9, 20, 22, 29, 33.
Litigation and claims
The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiff's Steering Committee (PSC) provides for a
court-supervised settlement programme, the Deepwater Horizon Court Supervised Settlement Programme (DHCSSP), which commenced operation on
4 June 2012. On 22 January 2021, the United States District Court for the Eastern District of Louisiana issued an order determining the completion of
all claims processing operations of the DHCSSP. The Court also concluded that future issues concerning EPD Settlement Agreement claims would be
time barred under the DHCSSP and the claim administrator would proceed to complete post-closure administrative wind down activities. Amounts
payable for settled economic and property damage claims are reported within payables - see Note 22 for further information.
A separate claims administrator was appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action Settlement.
For further information on the PSC settlements, see Legal proceedings on page 226.
The litigation and claims provision reflects the latest estimate for the remaining costs associated with the Gulf of Mexico oil spill. The amounts payable
may differ from the amount provided and the timing of payments is uncertain.
24. Pensions and other post-retirement benefits
Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension
benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of
schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the value of funds arising
from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as an employee’s
pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately
administered trusts.
For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement benefits
in Note 1.
The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an
annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated
directors, one independent director and one independent chairman nominated by the company. The trustee board is required by law to act in the best
interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The UK plan is closed to new
joiners and is currently under consultation for closure to future accrual. As at 31 December 2020, it remained open to ongoing accrual for current
members. New joiners in the UK are eligible for membership of a defined contribution plan.
In the US, all pension benefits now accrue under a cash balance formula. Benefits previously accrued under final salary formulas are legally protected.
Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded and its assets are
overseen by a fiduciary Investment Committee. During 2020 the committee was composed of seven bp employees appointed by the president of bp
Corporation North America Inc. (the appointing officer). The Investment Committee is required by law to act in the best interests of the plan participants
and is responsible for setting certain policies, such as the investment policies of the plan. US employees are also eligible to participate in a defined
contribution (401k) plan in which employee contributions are matched with company contributions. In the US, group companies also provide post-
retirement healthcare to most retired employees and their dependants (and, in certain cases, life insurance coverage); the entitlement to these benefits
is usually based on the employee remaining in service until a specified age and completion of a minimum period of service.
bp Annual Report and Form 20-F 2020
197
24. Pensions and other post-retirement benefits – continued
In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the majority
of the pensions are unfunded, in line with market practice. In Germany, the group’s largest Eurozone plan, employees receive a pension and also have a
choice to supplement their core pension through salary sacrifice. For employees who joined since 2002, the core pension benefit is a career average
plan with retirement benefits based on such factors as an employee’s pensionable salary and length of service. The returns on the notional
contributions made by both the company and employees are based on the interest rate which is set out in German tax law. Retired German employees
take their pension benefit typically in the form of an annuity. The German plans are governed by legal agreements between bp and the works council or
between bp and the trade union.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due.
During 2020 the aggregate level of contributions was $325 million (2019 $349 million and 2018 $610 million). The aggregate level of contributions in
2021 is expected to be approximately $400 million, and includes contributions in all countries that we expect to be required to make contributions by
law or under contractual agreements, as well as an allowance for discretionary funding.
For the primary UK plan there is a funding agreement between the group and the trustee. On an annual basis a schedule of contributions is agreed
covering the next five years. Contractually committed funding amounted to $1,014 million at 31 December 2020, all of which relates to future service.
This amount is included in the group’s committed cash flows relating to pensions and other post-retirement benefit plans as set out in the table of
contractual obligations on page 307.
The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any
remaining assets once all members have left the plan.
Minimum pension funding in the US is determined by legislation and is supplemented by discretionary contributions. No contributions were made into
the primary US pension plan in 2020 and no statutory funding requirement is expected in the next 12 months.
The surplus relating to the primary US fund is recognized on the balance sheet on the basis that economic benefit can be gained from the surplus
through a reduction in future contributions.
There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December
2020.
The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date
of the most recent actuarial review was 31 December 2020. The UK plans are subject to a formal actuarial valuation every three years; valuations are
required more frequently in many other countries.The most recent formal actuarial valuation of the UK pension plans was as at 31 December 2017, and
a valuation as at 31 December 2020 is currently underway. A valuation of the US plan and largest Eurozone plans are carried out annually.
The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed by
management at the end of each year and are used to evaluate the accrued benefit obligation at 31 December and pension expense for the following
year.
Financial assumptions used to determine benefit obligation
Discount rate for plan liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inflation for plan liabilities
Financial assumptions used to determine benefit expense
Discount rate for plan service cost
Discount rate for plan other finance expense
Inflation for plan service cost
2020
1.4
3.6
2.8
2.8
2.9
2020
2.1
2.1
2.6
2019
2.1
3.4
2.7
2.7
2.7
2019
3.0
2.9
3.1
UK
2018
2.9
3.8
3.0
3.0
3.1
UK
2018
2.6
2.5
3.1
2020
2.2
4.1
—
—
1.7
2020
3.2
3.1
1.5
2019
3.1
3.9
—
—
1.5
2019
4.2
4.1
1.5
US
2018
4.1
3.9
—
—
1.5
US
2018
3.6
3.5
1.7
2020
1.0
2.9
1.3
0.5
1.5
2020
1.8
1.3
1.7
%
Eurozone
2018
2.0
3.1
1.5
0.5
1.7
%
Eurozone
2018
2.4
1.9
1.6
2019
1.3
3.1
1.5
0.5
1.7
2019
2.5
2.0
1.7
The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone we use
yields that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the
difference between the yields on index-linked and fixed-interest long-term government bonds. In other countries, including the Eurozone, we use this
approach, or advice from the local actuary depending on the information available. The inflation assumptions are used to determine the rate of increase
for pensions in payment and the rate of increase in deferred pensions where there is such an increase.
The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary growth.
These include an allowance for promotion-related salary growth, of up to 0.8% depending on country.
198
bp Annual Report and Form 20-F 2020
Financial statements
24. Pensions and other post-retirement benefits – continued
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best
practice in the countries in which we provide pensions and have been chosen with regard to applicable published tables adjusted where appropriate to
reflect the experience of the group and an extrapolation of past longevity improvements into the future. bp’s most substantial pension liabilities are in
the UK, the US and the Eurozone where our mortality assumptions are as follows:
Mortality assumptions
Life expectancy at age 60 for a male currently
aged 60
Life expectancy at age 60 for a male currently
aged 40
Life expectancy at age 60 for a female currently
aged 60
Life expectancy at age 60 for a female currently
aged 40
2020
2019
UK
2018
2020
2019
US
2018
Years
Eurozone
2020
2019
2018
26.9
27.3
27.4
24.7
24.9
25.1
25.7
25.7
25.6
28.4
28.9
28.9
26.4
26.7
26.9
28.2
28.3
28.1
28.8
28.7
28.8
27.7
28.0
28.5
29.0
29.1
29.0
30.4
30.5
30.6
29.2
29.7
30.1
31.2
31.2
31.2
Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the plans.
The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio
management.
A significant proportion of the assets are held in equities, which are expected to generate a higher level of return over the long term, with an acceptable
level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the
investment portfolios are highly diversified.
The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the
plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI) approach
for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of
interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing
bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to
increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the
table below.
For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over
time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. During 2020, the UK plan
switched 11% of plan assets from equities to bonds (2019 2%). There is a similar agreement in place for the primary US plan, although no switches
have taken place in 2019 or 2020.
The current asset allocation policy for the major plans at 31 December 2020 was as follows:
Asset category
Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate
UK
%
17
76
7
US
%
40
60
—
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2020 were $4,217 million (2019 $4,804 million) of
government-issued nominal bonds and $24,576 million (2019 $19,462 million) of index-linked bonds.
Some of the group’s pension plans in the Eurozone and other countries use derivative financial instruments as part of their asset mix to manage the
level of risk. The fair value of these instruments is included in other assets in the table below.
The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.
The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the
effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 201.
bp Annual Report and Form 20-F 2020
199
24. Pensions and other post-retirement benefits – continued
Fair value of pension plan assets
At 31 December 2020
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bondsd
Government issued index-linked bondsd
Corporate bondsd
Propertye
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
At 31 December 2019
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bondsd
Government issued index-linked bondsd
Corporate bondsd
Propertye
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
At 31 December 2018
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bondsd
Government issued index-linked bondsd
Corporate bondsd
Propertye
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
UKa
USb
Eurozone
Other
5,008
418
2,899
4,303
24,576
8,906
2,553
1,392
795
(9,387)
41,463
6,285
1,096
2,675
4,884
19,462
6,132
2,507
426
98
(7,436)
36,129
5,191
950
2,792
4,263
17,491
4,606
2,311
376
116
(6,011)
1,112
115
1,604
1,839
—
2,398
—
267
131
—
7,466
1,290
124
1,474
2,100
—
2,304
—
289
74
—
7,655
1,238
63
1,495
2,072
—
2,184
6
73
64
—
542
68
—
1,111
107
587
110
51
104
—
2,680
495
61
—
959
100
569
96
33
30
—
2,343
413
65
—
895
102
506
57
42
32
—
318
70
4
616
—
279
28
163
30
—
1,508
371
64
3
572
—
256
27
93
26
—
1,412
306
56
4
533
—
243
25
83
40
—
$ million
Total
6,980
671
4,507
7,869
24,683
12,170
2,691
1,873
1,060
(9,387)
53,117
8,441
1,345
4,152
8,515
19,562
9,261
2,630
841
228
(7,436)
47,539
7,148
1,134
4,291
7,763
17,593
7,539
2,399
574
252
(6,011)
32,085
a Bonds held by the UK pension plans are denominated in sterling. Property held by the UK pension plans is in the United Kingdom.
b Bonds held by the US pension plans are denominated in US dollars.
c Private equity is valued at fair value based on the most recent transaction price or third-party net asset, revenue or earnings based valuations that generally result in the use of significant unobservable
2,112
7,195
1,290
42,682
inputs.
d Bonds held by pension plans are valued using quoted prices in active markets.
e Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party professional valuers that generally result in the use of significant
unobservable inputs.
200
bp Annual Report and Form 20-F 2020
24. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit or loss
Current service costa
Past service costb
Settlementb
Operating charge relating to defined benefit plans
Payments to defined contribution plans
Total operating charge
Interest income on plan assetsa
Interest on plan liabilities
Other finance (income) expense
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Remeasurements recognized in other comprehensive income
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Operating charge relating to defined benefit plans
Interest cost
Contributions by plan participantsc
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Reclassified as assets held for sale
Disposals
Remeasurements
Benefit obligation at 31 Decembera e
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsa f
Contributions by plan participantsc
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Reclassified as assets held for sale
Remeasurementsf
Fair value of plan assets at 31 Decemberg
Surplus (deficit) at 31 December
Represented by
Asset recognized
Liability recognized
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded
Unfunded
Financial statements
UK
US
Eurozone
Other
$ million
2020
Total
250
(48)
—
202
49
251
(725)
596
(129)
292
(66)
(23)
203
183
386
(210)
289
79
4,108 1,041
(4,207) (1,178)
29
(101)
(209)
585
54
540
103
12
10
125
2
127
(33)
97
64
104
(143)
56
(178)
(161)
683
38
(122)
(20)
(14)
(1)
547
17
272
38
55
819
(40) (1,008)
59 1,041
33
19
38 5,291
(42) (5,570)
666
(217)
170
(4)
8
—
29,780 10,119 7,353 1,826 49,078
64 2,087
1,303
—
17
202
547
203
59 1,041
596
289
34
11
21
—
(86) (2,899)
(1,291) (1,441)
(504)
(34)
(197)
(56)
—
(1)
—
(35)
(35)
38 5,121
3,568 1,250
34,171 10,187 8,161 1,895 54,414
720
125
97
2
(81)
(265)
(55)
—
265
(8)
—
—
36,129 7,655 2,343 1,412 47,539
64 1,881
1,582
—
40 1,008
725
210
34
11
21
—
29
325
189
8
(86) (2,899)
(1,291) (1,441)
(62)
—
(7)
4,108 1,041
38 5,291
41,463 7,466 2,680 1,508 53,117
(387) (1,297)
7,292 (2,721) (5,481)
235
33
2
99
(81)
(55)
104
—
7,567
59
269
(275) (2,990) (5,540)
7,292 (2,721) (5,481)
62 7,957
(449) (9,254)
(387) (1,297)
7,564
(109)
269
(272) (2,990) (5,372)
7,292 (2,721) (5,481)
(58) 7,666
(329) (8,963)
(387) (1,297)
(33,899) (7,197) (2,789) (1,566) (45,451)
(329) (8,963)
(34,171) (10,187) (8,161) (1,895) (54,414)
(272) (2,990) (5,372)
a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of
administering other post-retirement benefit plans are included in the benefit obligation.
b Past service credits represent curtailment gains arising from restructuring programmes in the UK, US and other countries, whilst past service costs and settlements in the Eurozone represent charges
for special termination benefits reflecting the increased liability arising as a result of early retirements. Settlement costs in the US resulted from a pension risk transfer to an external carrier for a group
of small benefit retirees.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $2,935 million benefits and $428 million settlements, plus $40 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $7,728 million for pension liabilities and $2,459 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical
liabilities). The benefit obligation for the Eurozone includes $5,060 million for pension liabilities in Germany which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
g The fair value of plan assets includes borrowings related to the LDI programme as described on page 199.
bp Annual Report and Form 20-F 2020
201
24. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit or loss
Current service costa
Past service costb
Settlementb
Operating charge relating to defined benefit plans
Payments to defined contribution plans
Total operating charge
Interest income on plan assetsa
Interest on plan liabilities
Other finance (income) expense
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Remeasurements recognized in other comprehensive income
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Operating charge relating to defined benefit plans
Interest cost
Contributions by plan participantsc
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Reclassified as assets held for sale
Disposals
Remeasurements
Benefit obligation at 31 Decembera e
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsa f
Contributions by plan participantsc
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Reclassified as assets held for sale
Remeasurementsf
Fair value of plan assets at 31 Decemberg
Surplus (deficit) at 31 December
Represented by
Asset recognized
Liability recognized
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded
Unfunded
UK
US
Eurozone
Other
$ million
2019
Total
227
2
—
229
42
271
(909)
757
(152)
263
—
(13)
250
188
438
(285)
387
102
2,945 1,079
(1,036)
91
(22)
112
(2,294)
136
(57)
730
81
5
8
94
7
101
(43)
133
90
220
(748)
3
6
(519)
609
38
6
(1)
(5)
—
610
37
275
38
885
75
(46)
(1,283)
69 1,346
63
23
97 4,341
(4,170)
(92)
226
(4)
(69)
4
328
5
26,830 9,696 6,906 1,686 45,118
942
826
26
229
37
610
757
69 1,346
20
28
6
(1,207)
(2,188)
(75)
(6)
(499)
(15)
—
(146)
—
—
—
(30)
92 4,013
2,215
29,780 10,119 7,353 1,826 49,078
—
250
387
—
(830)
(205)
(146)
—
967
(142)
94
133
2
(76)
(273)
—
(30)
739
32,085 7,195 2,112 1,290 42,682
24 1,122
1,141
—
46 1,283
909
285
6
28
20
—
24
349
236
4
(75)
(2,188)
(1,207)
(830)
(78)
—
—
(78)
2,945 1,079
97 4,341
36,129 7,655 2,343 1,412 47,539
(1,539)
6,349
(43)
43
2
85
(76)
—
220
(5,010)
(2,464)
(414)
6,588
(239)
6,349
387
(2,851)
(2,464)
27
(5,037)
(5,010)
51 7,053
(8,592)
(1,539)
(465)
(414)
6,588
(239)
6,349
387
(2,851)
(2,464)
(136)
(4,874)
(5,010)
(87) 6,752
(8,291)
(1,539)
(327)
(414)
(29,541)
(239)
(7,268)
(2,851)
(29,780) (10,119)
(2,479)
(4,874)
(7,353)
(1,499) (40,787)
(8,291)
(1,826) (49,078)
(327)
a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of
administering other post-retirement benefit plans are included in the benefit obligation.
b Past service costs and settlements have arisen from restructuring programmes and represent charges for special termination benefits reflecting the increased liability arising as a result of early
retirements. Settlements in the US are the result of a buy-out transaction for the pensions of a group of low value annuitants.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $2,304 million benefits and $346 million settlements, plus $37 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $7,789 million for pension liabilities and $2,330 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical
liabilities). The benefit obligation for the Eurozone includes $4,567 million for pension liabilities in Germany which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
g The fair value of plan assets includes borrowings related to the LDI programme as described on page 199.
202
bp Annual Report and Form 20-F 2020
Financial statements
UK
US
Eurozone
Other
$ million
2018
Total
24. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit or loss
Current service costa
Past service costb
Settlement
295
15
—
310
38
348
(868)
774
(94)
299
—
—
299
178
477
(262)
369
107
84
9
17
110
5
115
(44)
136
92
721
43
28
4
17
—
766
47
40
261
87 1,027
(45)
(1,219)
67 1,346
127
22
Operating charge relating to defined benefit plans
Payments to defined contribution plans
Total operating charge
Interest income on plan assetsa
Interest on plan liabilities
Other finance (income) expense
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Remeasurements recognized in other comprehensive income
a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of
(722)
1,770
123
520
1,691
(69)
14
(42)
(43)
(140)
(256)
945
(9)
41
721
(36)
(1,083)
65 2,794
79
527
45 2,317
7
9
administering other post-retirement benefit plans are included in the benefit obligation.
b Past service costs have arisen from restructuring programmes and represent charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in
the UK and Eurozone.
Sensitivity analysis
The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point
change, in isolation, in certain assumptions as at 31 December 2020 for the group’s pensions and other post-retirement benefit expense would have
had the effects shown in the tables below. The effects shown for the expense in 2021 comprise the total of current service cost and net finance
income or expense.
Discount ratea
Effect on expense in 2021
Effect on obligation at 31 December 2020
Inflation rateb
Effect on expense in 2021
Effect on obligation at 31 December 2020
Salary growth
Effect on expense in 2021
Effect on obligation at 31 December 2020
UK
US
Eurozone
Increase
Decrease
Increase
Decrease
Increase
Decrease
$ million
One percentage point
(274)
198
(5,658) 7,690
(51)
36
(1,272) 1,556
(2)
(11)
(1,149) 1,452
145
(116)
5,337 (4,482)
31
670
(27)
(585)
10
66
12
82
(8)
(55)
35
1,025
(28)
(870)
(10)
(69)
7
91
(7)
(89)
a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.
Longevity
Effect on expense in 2021
Effect on obligation at 31 December 2020
$ million
One year increase
UK
US
Eurozone
28
1,406
5
150
8
333
Estimated future benefit payments and the weighted average duration of defined benefit obligations
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2030 and the weighted
average duration of the defined benefit obligations at 31 December 2020 are as follows:
Estimated future benefit payments
2021
2022
2023
2024
2025
2026-2030
UK
1,072
1,086
1,120
1,141
1,135
5,939
US
1,568
612
593
575
583
2,696
Eurozone
357
346
339
332
328
1,521
Other
112
109
107
108
107
528
$ million
Total
3,109
2,153
2,159
2,156
2,153
10,684
Years
Weighted average duration
19.2
13.8
16.1
12.7
bp Annual Report and Form 20-F 2020
203
25. Cash and cash equivalents
Cash
Triparty repos and term bank deposits
Cash equivalents (excluding triparty repos and term bank deposits)
2020
6,235
17,368
7,508
31,111
$ million
2019
6,462
10,296
5,714
22,472
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; deposits of three months or less with banks and
similar institutions; money market funds and commercial paper. The carrying amounts of cash, triparty repos and term bank deposits approximate their
fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy.
Cash and cash equivalents at 31 December 2020 includes $1,917 million (2019 $1,676 million) that is restricted. The restricted cash balances include
amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls.
The group holds $3,890 million (2019 $4,678 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax will arise
on repatriation.
26. Finance debt
Borrowings
Current
9,359
Non-current
63,305
2020
Total
72,664
Current
10,487
Non-current
57,237
$ million
2019
Total
67,724
The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $8,122
million (2019 $8,166 million) and issued commercial paper of $1,004 million (2019 $2,279 million). Finance debt does not include accrued interest,
which is reported within other payables. As part of actively managing its debt portfolio, during the year the group bought back $4.0 billion equivalent
(2019 $nil) of euro and sterling bonds and terminated derivatives associated with the debt bought back. In addition on 18 December 2020 the group
exercised its option to redeem finance debt with an outstanding aggregate principal amount of $2.0 billion on 22 January 2021. On 19 March 2021 the
group bought back a further $1.9 billion equivalent of euro and sterling bonds and terminated associated derivatives. These transactions have no
significant impact on net debt or gearing.
The following table shows the weighted-average interest rates achieved through a combination of borrowings and derivative financial instruments
entered into to manage interest rate and currency exposures.
US dollar
Other currencies
US dollar
Other currencies
Fixed rate debt
Floating rate debt
Total
Weighted
average
interest
rate
%
Weighted
average
time for
which rate
is fixed
Years
3
6
4
6
8
9
5
10
Weighted
average
interest
rate
%
2
5
3
7
Amount
$ million
39,452
178
39,630
25,634
183
25,817
Amount
$ million
32,891
143
33,034
41,871
36
41,907
Amount
$ million
2020
72,343
321
72,664
2019
67,505
219
67,724
Fair values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2020, whereas in the group
balance sheet the amount is reported within current finance debt.
The carrying amount of the group’s short-term borrowings, comprising mainly of commercial paper, approximates their fair value. The fair values of the
significant majority of the group’s long-term borrowings are determined using quoted prices in active markets, and so fall within level 1 of the fair value
hierarchy. Where quoted prices are not available, quoted prices for similar instruments in active markets are used and such measurements are
therefore categorized in level 2 of the fair value hierarchy.
Short-term borrowings
Long-term borrowings
Total finance debt
204
bp Annual Report and Form 20-F 2020
2020
Carrying
amount
1,237
71,427
72,664
Fair value
2,321
67,055
69,376
Fair value
1,237
74,855
76,092
$ million
2019
Carrying
amount
2,321
65,403
67,724
27. Capital disclosures and net debt
The group defines capital as total equity plus net debt. We maintain our financial framework to support the pursuit of value growth for shareholders,
while ensuring a secure financial base.
The group monitors capital on basis of gearing, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as finance debt, as shown in
the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks
relating to finance debt for which hedge accounting is applied, less cash and cash equivalents. Net debt and gearing are non-GAAP measures. bp
believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of finance debt, related hedges
and cash and cash equivalents in total. Gearing enables investors to see how significant net debt is relative to total equity. The derivatives are reported
on the balance sheet within the headings ‘Derivative financial instruments’. All components of equity are included in the denominator of the calculation.
Financial statements
At 31 December 2020, gearing was 31.3% (2019 31.1%).
At 31 December
Finance debt
Less: fair value asset (liability) of hedges related to finance debta
Less: cash and cash equivalents
Net debt
Total equityb
Gearing
2020
$ million
2019
72,664
2,612
70,052
31,111
38,941
85,568
67,724
(190)
67,914
22,472
45,442
100,708
31.3 %
31.1 %
a Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of $236 million (2019
liability of $601 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.
b Total equity in 2020 includes perpetual hybrid bonds issued on 17 June 2020. See Note 32 for further information.
An analysis of changes in liabilities arising from financing activities is provided below.
At 1 January 2020
Exchange adjustments
Net financing cash flow
Fair value (gains) losses
New and remeasured leases/joint operation payables
Other movements
At 31 December 2020
Finance
debt
67,724
349
1,589
2,612
—
390
72,664
Currency
swapsa Lease liabilities
918
—
(226)
(3,734)
—
77
(2,965)
9,722
181
(2,442)
—
1,579
222
9,262
Net partner
payable for
leases entered
into on behalf
of joint
operations
290
4
(40)
—
20
(7)
267
$ million
Total liabilities
arising from
financing
activities
78,654
534
(1,119)
(1,122)
1,599
682
79,228
At 1 January 2019
Adjustment on adoption of IFRS16
Exchange adjustments
Net financing cash flow
Fair value (gains) losses
New and remeasured leases/joint operations payables
Other movements
At 31 December 2019
a Previously reported in this column were hedge accounted derivatives related to finance debt. This has been updated in 2020 as described below and comparatives provided on a consistent basis.
65,132
—
(62)
1,671
924
—
59
67,724
667
9,233
(4)
(2,372)
—
2,614
(416)
9,722
1,486
—
—
2
(570)
—
—
918
—
217
8
(14)
—
82
(3)
290
67,285
9,450
(58)
(713)
354
2,696
(360)
78,654
Currency swaps include cross currency interest rate swaps.
The balances above do not include accrued interest, which is reported within other receivables and other payables on the balance sheet and for which
the associated cash flows are presented as operating cash flows in the group cash flow statement. The currency swaps are reported on the balance
sheet within the headings 'Derivative financial instruments' and are subsets of both derivatives held for trading and derivatives designated in fair value
hedge relationships as detailed in Note 30. When hedge accounting is applied to these derivatives they are included in the calculation of net debt shown
above.
bp Annual Report and Form 20-F 2020
205
28. Leases
The group leases a number of assets as part of its activities. This primarily includes drilling rigs in the Upstream segment and retail service stations, oil
depots and storage tanks in the Downstream segment as well as office accommodation and vessel charters across the group. The weighted-average
remaining lease term for the total lease portfolio is around 8 years (2019 9 years). Some leases will have payments that vary with market interest or
inflation rates. Certain leases contain residual value guarantees, which may be triggered in certain circumstances such as if market values have
significantly declined at the conclusion of the lease.
The table below shows the timing of the undiscounted cash outflows for the lease liabilities included on the balance sheet.
Undiscounted lease liability cash flows due:
Within 1 year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
Impact of discounting
Lease liabilities at 31 December
Of which – current
– non-current
2020
2,262
1,672
1,340
1,025
878
2,192
1,515
10,884
(1,622)
9,262
1,933
7,329
$ million
2019
2,514
1,839
1,364
1,105
876
2,427
1,174
11,299
(1,577)
9,722
2,067
7,655
The group may enter into lease arrangements a number of years before taking control of the underlying asset due to construction lead times or to
secure future operational requirements. The total undiscounted amount for future commitments for leases not yet commenced as at 31 December
2020 is $5,309 million (2019 $5,688 million). The majority of this future commitment relates to the floating LNG vessel to service the Greater Tortue
Ahmeyim project from 2023.
Total cash outflow for amounts included in lease liabilitiesa
Expense for variable payments not included in the lease liability
Short-term lease expense
Additions to right-of-use assets in the period
Gain on sale and leaseback transactions
a The cash outflows for amounts not included in lease liabilities approximate the income statement expense disclosed above.
An analysis of right-of-use assets and depreciation is provided in Note 12. An analysis of lease interest expense is provided in Note 7.
2020
2,779
41
621
1,714
187
29. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments and their carrying amounts are set out below.
$ million
2019
2,709
67
331
2,542
—
$ million
Mandatorily
measured at
fair value
through profit
or loss
Measured at
amortized cost
Derivative
hedging
instruments
Total carrying
amount
—
929
20,252
—
24,905
(44,960)
—
(5,502)
(9,262)
(72,664)
(86,302)
3,079
369
—
10,049
6,206
—
(8,320)
—
—
—
11,383
—
—
—
2,698
—
—
(82)
—
—
—
2,616
3,079
1,298
20,252
12,747
31,111
(44,960)
(8,402)
(5,502)
(9,262)
(72,664)
(72,303)
Note
18
20
30
25
22
30
28
26
At 31 December 2020
Financial assets
Other investments
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debt
206
bp Annual Report and Form 20-F 2020
29. Financial instruments and financial risk factors – continued
At 31 December 2019
Financial assets
Other investments
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Lease liabilities
Finance debt
Financial statements
Measured at
amortized cost
Mandatorily
measured at fair
value through
profit or loss
Derivative
hedging
instruments
Total carrying
amount
$ million
—
906
24,271
—
18,183
(55,891)
—
(6,062)
(9,722)
(67,724)
(96,039)
1,445
63
—
9,984
4,289
—
(8,122)
—
—
—
7,659
—
—
—
483
—
—
(676)
—
—
—
(193)
1,445
969
24,271
10,467
22,472
(55,891)
(8,798)
(6,062)
(9,722)
(67,724)
(88,573)
Note
18
20
30
25
22
30
28
26
The fair value of finance debt is shown in Note 26. For all other financial instruments within the scope of IFRS 9, the carrying amount is either the fair
value, or approximates the fair value.
Information on gains and losses on derivative financial assets and financial liabilities classified as measured at fair value through profit or loss is provided
in the derivative gains and losses section of Note 30. Fair value gains and losses related to other assets and liabilities classified as measured at fair
value through profit or loss totalled a net gain of $367 million (2019 net loss of $129 million). Dividend income of $17 million (2019 $20 million) from
investments in equity instruments classified as measured at fair value through profit or loss is presented within other income - see Note 7.
Interest income and expenses arising on financial instruments are disclosed in Note 7.
Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including
market risks relating to commodity prices; foreign currency exchange rates and interest rates; credit risk; and liquidity risk.
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is
chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated
supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for
the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial
risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with
group policies and group risk appetite.
The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading function. Treasury
holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt and hybrid bond issuance; the
compliance, control, and risk management processes for these activities are managed within the treasury function. All other foreign exchange and
interest rate activities within financial markets are performed within the integrated supply and trading function and are also underpinned by the
compliance, control and risk management infrastructure common to the activities of bp’s integrated supply and trading function. All derivative activity is
carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management
control.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk, credit risk and operational risk
associated with trading activity. A policy and risk committee approves value-at-risk delegations, reviews incidents and validates risk-related policies,
methodologies and procedures. A commitments committee approves the trading of new products, instruments and strategies and material
commitments.
In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a control framework as
described more fully below.
(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The
primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s
financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In
addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In
accordance with the control framework the group enters into various transactions using derivatives for risk management purposes.
The major components of market risk are commodity price risk, foreign currency exchange risk and interest rate risk, each of which is discussed below.
(i) Commodity price risk
The group’s integrated, supply and trading function is responsible for delivering value across the overall crude, oil products, gas and power supply
chains. As such, it routinely enters into spot and term physical commodity contracts in addition to optimising physical storage, pipeline and
transportation capacity. These activities expose the group to commodity price risk which is managed by entering into oil and natural gas swaps, options
and futures.
The group measures market risk exposure arising from its trading positions in liquid periods using value-at-risk techniques based on Variance/
Covariance or Monte Carlo simulation models. These techniques make a statistical assessment of the market risk arising from possible future changes
in market prices over a one-day holding period within a 95% confidence level. The value-at-risk measure is supplemented by stress testing and scenario
analysis through simulating the financial impact of certain physical, economic and geo-political scenarios. Trading activity occurring in liquid periods is
bp Annual Report and Form 20-F 2020
207
29. Financial instruments and financial risk factors – continued
subject to value-at-risk and other limits for each trading activity and the aggregate of all trading activity. The board has delegated a limit of $100 million
(2019 $100 million) value at risk in support of this trading activity. Alternative measures are used to monitor exposures which are outside liquid periods
and for which value-at-risk techniques are not appropriate.
(ii) Foreign currency exchange risk
Since bp has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and future
expenditure commitments. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost
competitiveness, lags in market adjustment to movements in rates and translation differences accounted for on specific transactions. For this reason,
the total effect of exchange rate fluctuations is not identifiable separately in the group’s reported results. The main underlying economic currency of the
group’s cash flows is the US dollar. This is because bp’s major product, oil, is priced internationally in US dollars. bp’s foreign currency exchange
management policy is to limit economic and material transactional exposures arising from currency movements against the US dollar. The group co-
ordinates the handling of foreign currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible and then
managing any material residual foreign currency exchange risks.
Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2020, the total foreign currency
borrowings not swapped into US dollars amounted to $321 million (2019 $219 million). During the year the group issued perpetual subordinated hybrid
bonds in euro, sterling and US dollars. Whilst the contractual terms of these instruments allow the group to defer coupon payments and the repayment
of principal indefinitely, the group has chosen to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective
first call periods.
The group manages the net residual foreign currency exposures by constantly reviewing the foreign currency economic value at risk and aims to
manage such risk to keep the 12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk
exceed the maximum risk limit. A continuous assessment is made in respect to the group’s foreign currency exposures to capture hedging
requirements.
During the year, hedge accounting was applied to foreign currency exposure to highly probable forecast capital expenditure commitments. The group
fixes the US dollar cost of non-US dollar supplies by using currency forwards for the highly probable forecast capital expenditure; the exposures are in
sterling, euro, Australian dollar and Korean won. At 31 December 2020 the most significant open contracts in place were for $124 million sterling (2019
$106 million sterling).
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-
risk techniques as explained in (i) commodity price risk above.
(iii) Interest rate risk
bp is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial
instruments, principally finance debt. While the group issues debt and hybrid bonds in a variety of currencies based on market opportunities, it uses
derivatives to swap the economic exposure to a floating rate basis, mainly to US dollar floating, but in certain defined circumstances maintains a US
dollar fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2020 was 45% of total
finance debt outstanding (2019 62%). The weighted average interest rate on finance debt at 31 December 2020 was 3% (2019 3%) and the weighted
average maturity of fixed rate debt was eight years (2019 five years).
The group’s earnings are sensitive to changes in interest rates on the element of the group’s finance debt that has been swapped to floating rates. If
the interest rates applicable to these floating rate instruments were to have changed by one percentage point on 1 January 2021, it is estimated that
the group’s finance costs for 2021 would change by approximately $330 million (2019 $419 million).
Financial authorities in the US, UK, EU and other territories are currently undertaking reviews of key interest rate benchmarks such as the London Inter-
bank Offered Rate (LIBOR) with a view to replacing them with alternative benchmarks. bp is significantly exposed to benchmark interest rate
components; predominantly USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. Following the completion of consultation processes, these financial
authorities have begun to announce the timing of both benchmark transitions and continued publication of synthetic benchmarks.
In October 2020 the International Swaps and Derivatives Association (ISDA) published its fallback protocol containing clauses to amend derivative
contracts on the cessation of LIBOR should an entity and its counterparties adhere to the protocol. The protocol’s pricing mechanism is at fair market
value and bp has signed up to the protocol as this removes transition uncertainty for any interest rate and cross-currency interest rate swap contracts of
the Group without fall-back clauses. The ISDA fallback protocol is expected to increase market activity and certainty such that corporates can finalize
their plans for implementation of the transition. bp continues to monitor regulatory and market developments over the course of the transition.
In response to the cessation of the interbank offered rates (IBORs), bp has set up an internal working group to monitor market developments and
manage the transition to alternative benchmark rates and is currently assessing the impact on contracts and arrangements that are linked to existing
interest rate benchmarks, for example, borrowings, leases and derivative contracts. bp is also participating on external committees and task forces
dedicated to interest rate benchmark reform.
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the
group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit
exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group companies under
which the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2020 was $1,405 million (2019 $692 million) in
respect of liabilities of joint ventures and associates and $661 million (2019 $523 million) in respect of liabilities of other third parties.
The group has a credit policy, approved by the CFO that is designed to ensure that consistent processes are in place throughout the group to measure
and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent
to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval
authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that
all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and
reporting of any non-approved credit exposures and credit losses. While each segment is responsible for its own credit risk management and reporting
consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for exposure to banks and financial
institutions. Standing credit controls and processes were augmented intra-year given heightened uncertainty from increased oil price volatility and the
evolving COVID-19 pandemic. Constraints on incoming credit risks were tightened, credit reporting and frequency was enhanced from the operational
to board level, and key credit risk strategies were reviewed and vetted.
208
bp Annual Report and Form 20-F 2020
Financial statements
29. Financial instruments and financial risk factors – continued
For the purposes of financial reporting the group calculates expected loss allowances based on the maximum contractual period over which the group
is exposed to credit risk. Lifetime expected credit losses are recognized for trade receivables and the credit risk associated with the significant majority
of financial assets measured at amortized cost is considered to be low. Since the tenor of substantially all of the group's in-scope financial assets is less
than 12 months there is no significant difference between the measurement of 12-month and lifetime expected credit losses. Expected loss
allowances for financial guarantee contracts are typically lower than their initial fair value less, where appropriate, amortization. Financial assets are
considered to be credit-impaired when there is reasonable and supportable evidence that one or more events that have a detrimental impact on the
estimated future cash flows of the financial asset have occurred. This includes observable data concerning significant financial difficulty of the
counterparty; a breach of contract; concession being granted to the counterparty for economic or contractual reasons relating to the counterparty’s
financial difficulty, that would not otherwise be considered; it becoming probable that the counterparty will enter bankruptcy or other financial re-
organization or an active market for the financial asset disappearing because of financial difficulties. The group also applies a rebuttable presumption
that an asset is credit-impaired when contractual payments are more than 30 days past due. Where the group has no reasonable expectation of
recovering a financial asset in its entirety or a portion thereof, for example where all legal avenues for collection of amounts due have been exhausted,
the financial asset (or relevant portion) is written off.
The measurement of expected credit losses is a function of the probability of default, loss given default (i.e. the magnitude of the loss after recovery if
there is a default) and the exposure at default (i.e. the asset's carrying amount). The group allocates a credit risk rating to exposures based on data that
is determined to be predictive of the risk of loss, including but not limited to external ratings. Probabilities of default derived from historical, current and
future-looking market data are assigned by credit risk rating with a loss given default based on historical experience and relevant market and academic
research applied by exposure type. Experienced credit judgement is applied to ensure probabilities of default are reflective of the credit risk associated
with the group's exposures. Credit enhancements that would reduce the group's credit losses in the event of default are reflected in the calculation
when they are considered integral to the related asset.
The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely
but expects to experience a certain level of credit losses. As at 31 December 2020, the group had in place credit enhancements designed to mitigate
approximately $5.4 billion (2019 $7.0 billion) of credit risk, of which substantially all relates to assets in the scope of IFRS 9's impairment requirements.
Credit enhancements include standby and documentary letters of credit, bank guarantees, insurance and liens which are typically taken out with
financial institutions who have investment grade credit ratings, or are liens over assets held by the counterparty of the related receivables. Reports are
regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by segment, and
overall quality of the portfolio.
Management information used to monitor credit risk, which reflects the impact of credit enhancements, indicates that the risk profile of financial assets
which are subject to review for impairment under IFRS 9 is as set out below.
As at 31 December
AAA to AA-
A+ to A-
BBB+ to BBB-
BB+ to BB-
B+ to B-
CCC+ and below
2020
11 %
59 %
8 %
6 %
13 %
3 %
%
2019
16 %
51 %
13 %
7 %
11 %
2 %
Movements in the impairment provision for trade and other receivables are shown in Note 21.
Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements
The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross basis, and
the amounts offset in the balance sheet.
Amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain conditions arise,
and collateral received or pledged, are also presented in the table to show the total net exposure of the group.
At 31 December 2020
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
At 31 December 2019
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
Gross
amounts of
recognized
financial
assets
(liabilities)
14,765
(10,414)
7,667
(7,862)
13,191
(11,445)
10,661
(10,266)
Related amounts not set off
in the balance sheet
Net amounts
presented on
the balance
sheet
12,746
(8,395)
3,988
(4,183)
Amounts
set off
(2,019)
2,019
(3,679)
3,679
(2,724)
2,724
(5,211)
5,211
10,467
(8,721)
5,450
(5,055)
Master
netting
arrangements
(2,075)
2,075
(693)
693
(1,971)
1,971
(961)
961
Cash
collateral
(received)
pledged
(386)
—
(122)
—
(206)
—
(190)
—
$ million
Net amount
10,285
(6,320)
3,173
(3,490)
8,290
(6,750)
4,299
(4,094)
bp Annual Report and Form 20-F 2020
209
29. Financial instruments and financial risk factors – continued
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed
centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations,
generally subsidiaries pool their cash surpluses to the treasury function, which will then arrange to fund other subsidiaries’ requirements, or invest any
net surplus in the market or arrange for necessary external borrowings, while managing the group’s overall net currency positions.
The group benefits from open credit provided by suppliers who generally sell on five to 60-day payment terms in accordance with industry norms. bp
utilizes various arrangements in order to manage its working capital and reduce volatility in cash flow. This includes discounting of receivables and, in
the supply and trading businesses, managing inventory, collateral and supplier payment terms within a maximum of 60 days.
It is normal practice in the oil and gas supply and trading business for customers and suppliers to utilise letter of credit (LC) facilities to mitigate credit
and non-performance risk. Consequently, LCs facilitate active trading in a global market where credit and performance risk can be significant. In
common with the industry, bp routinely provides LCs to some of its suppliers.
The group has committed LC facilities totalling $11,325 million (2019 $12,175 million), allowing LCs to be issued for a maximum 24-month duration.
There were also uncommitted secured LC facilities in place at 31 December 2020 for $3,460 million (2019 $4,440 million), which are secured against
inventories or receivables when utilized. The facilities are held with over 25 international banks. The uncommitted secured LC facilities can only be
terminated by either party giving a stipulated termination notice to the other.
In certain circumstances, the supplier has the option to request accelerated payment from the LC provider in order to further reduce their exposure.
bp’s payments are made to the provider of the LC rather than the supplier according to the original contractual payment terms. At 31 December 2020,
$5,250 million (2019 $4,755 million) of the group’s trade payables subject to these arrangements were payable to LC providers, with no material
exposure to any individual provider. If these facilities were not available, this could result in renegotiation of payment terms with suppliers such that
settlement periods were shorter.
Standard & Poor’s Ratings long-term credit rating for bp is A- (negative outlook) and Moody’s Investors Service rating is A1 (negative outlook) and the
Fitch Ratings' long-term credit rating is A (stable).
During 2020, $14 billion (2019 $8 billion) of long-term taxable bonds were issued with terms ranging from two to thirty years. In addition the group
issued perpetual hybrid bonds with a US dollar equivalent value of $11.9 billion. Commercial paper is issued at competitive rates to meet short-term
borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $31.1 billion at 31 December
2020 (2019 $22.5 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At
31 December 2020, the group had substantial amounts of undrawn borrowing facilities available, consisting of an undrawn committed $10.0 billion
credit facility and $7.6 billion (2019 $7.6 billion) of standby facilities. On 1st March 2021, following an assessment of liquidity requirements, the group
replaced these with new facility agreements, consisting of an undrawn committed $8.0 billion credit facility and $4.0 billion of standby facilities. The
facilities are available for three and five years respectively at pre-agreed margins and are with 27 international banks, and borrowings under them would
be at pre-agreed rates.
For further information on the group's sources and uses of cash see Liquidity and capital resources on page 306.
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of
both derivative assets and liabilities as indicated in Note 30. Management does not currently anticipate any cash flows, other than noted below, that
could be of a significantly different amount or could occur earlier than the expected maturity analysis provided.
The table below shows the timing of cash outflows relating to finance debt, trade and other payables and accruals. As part of actively managing the
group’s debt portfolio it is possible that cash flows in relation to finance debt could be accelerated from the profile provided. As a result of the 19 March
2021 debt buy back (see Note 26 for further information) $1.9 billion equivalent of cash outflows relating to finance debt that are presented in the table
with maturities of 2-8 years have occurred within one year of the balance sheet date.
2020
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
Accruals
4,650
157
184
87
217
108
99
5,502
a 2020 includes $14,569 million (2019 $16,129 million) in relation to the Gulf of Mexico oil spill, of which $13,160 million (2019 $14,501 million) matures in greater than one year.
1,778
1,477
1,305
1,110
919
2,408
1,037
10,034
Accruals
5,066
261
146
181
108
231
69
6,062
Finance
debt
9,119
6,292
7,031
8,047
6,652
22,156
10,008
69,305
Trade and
other
payablesa
33,290
1,728
1,590
1,332
1,335
4,570
4,419
48,264
Trade and
other
payablesa
43,699
1,937
1,465
1,409
1,332
5,863
3,957
59,662
Interest on
finance debt
Finance
debtb
10,065
6,726
7,949
7,022
7,554
23,540
2,497
65,353
$ million
2019
Interest on
finance debt
2,037
1,641
1,409
1,172
942
1,970
249
9,420
210
bp Annual Report and Form 20-F 2020
29. Financial instruments and financial risk factors – continued
The table below shows the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate and
foreign currency exchange risk, whether or not hedge accounting is applied, based upon contractual payment dates. As part of actively managing the
group’s debt portfolio it is possible that cash flows in relation to associated derivatives could be accelerated from the profile provided. The amounts
reflect the gross settlement amount where the pay leg of a derivative will be settled separately from the receive leg, as in the case of cross-currency
swaps hedging non-US dollar finance debt or hybrid bonds. The swaps are with high investment-grade counterparties and therefore the settlement-day
risk exposure is considered to be negligible. Not shown in the table are the gross settlement amounts (inflows) for the receive leg of derivatives that
are settled separately from the pay leg, which amount to $33,704 million at 31 December 2020 (2019 $24,787 million) to be received on the same day
as the related cash outflows. As a result of the termination of derivatives associated with the 19 March 2021 debt buy back (see Note 26 for further
information) $1.8 billion of cash outflows that are presented in the table with maturities of 2-8 years and $1.9 billion equivalent of cash inflows on the
receive legs have occurred within one year of the balance sheet date.
Financial statements
Cash outflows for derivative financial instruments at 31 December
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
For further information on our derivative financial instruments, see Note 30.
2020
2,384
1,976
2,017
3,074
2,582
15,263
4,483
31,779
$ million
2019
1,678
2,384
2,838
2,906
3,321
10,633
2,224
25,984
30. Derivative financial instruments
In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation
to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate
debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies pursued in
relation to those risks is set out in Note 29. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in
conjunction with these activities using a similar range of contracts.
For information on significant estimates and judgements made in relation to the valuation of derivatives see Derivative financial instruments within Note
1.
The fair values of derivative financial instruments at 31 December are set out below.
Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized
within level 1 of the fair value hierarchy. Exchange traded derivatives are typically considered settled through the (normally daily) payment or receipt of
variation margin.
Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally valued using readily available information in
the public markets and quotations provided by brokers and price index developers. These quotes are corroborated with market data and are categorized
within level 2 of the fair value hierarchy.
In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and
physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between
various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value
hierarchy.
bp Annual Report and Form 20-F 2020
211
30. Derivative financial instruments – continued
Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic factors.
The degree to which these inputs are observable in the forward markets determines whether the option is categorized within level 2 or level 3 of the
fair value hierarchy.
Derivatives held for trading
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Embedded derivatives
Other embedded derivatives
Cash flow hedges
Currency forwards
Gas price futures
Fair value hedges
Currency swaps
Interest rate swaps
Of which – current
– non-current
Fair value
asset
858
1,519
6,406
1,258
7
10,048
1
1
4
—
4
2020
Fair value
liability
Fair value
asset
(694)
(1,093)
(5,489)
(1,037)
—
(8,313)
(7)
(7)
—
—
—
81
1,918
6,569
1,306
110
9,984
—
—
1
—
1
2,614
80
2,694
12,747
2,992
9,755
(82)
—
(82)
(8,402)
(2,998)
(5,404)
344
138
482
10,467
4,153
6,314
$ million
2019
Fair value
liability
(744)
(1,478)
(4,871)
(952)
—
(8,045)
(77)
(77)
(4)
—
(4)
(637)
(35)
(672)
(8,798)
(3,261)
(5,537)
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy
supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and
are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract
types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is
monitored using market value-at-risk techniques as described in Note 29.
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Derivative assets held for trading have the following fair values and maturities.
Less than
1 year
153
1,159
1,210
425
—
2,947
Less than
1 year
48
1,619
1,889
556
33
4,145
1-2 years
2-3 years
3-4 years
4-5 years
9
197
731
223
—
1,160
3
90
596
161
7
857
2
63
525
107
—
697
2
7
476
76
—
561
1-2 years
2-3 years
3-4 years
4-5 years
23
114
824
269
—
1,230
9
76
615
146
—
846
1
53
489
94
77
714
—
45
433
67
—
545
$ million
2020
Total
858
1,519
6,406
1,258
7
10,048
$ million
2019
Total
81
1,918
6,569
1,306
110
9,984
Over
5 years
689
3
2,868
266
—
3,826
Over
5 years
—
11
2,319
174
—
2,504
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
212
bp Annual Report and Form 20-F 2020
30. Derivative financial instruments – continued
Derivative liabilities held for trading have the following fair values and maturities.
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Less than
1 year
(502)
(1,000)
(1,095)
(345)
(2,942)
Less than
1 year
(166)
(1,405)
(1,070)
(395)
(3,036)
1-2 years
2-3 years
3-4 years
4-5 years
(117)
(83)
(595)
(184)
(979)
(11)
(9)
(479)
(126)
(625)
(1)
(1)
(422)
(81)
(505)
—
—
(348)
(68)
(416)
1-2 years
2-3 years
3-4 years
4-5 years
(283)
(56)
(522)
(165)
(1,026)
(201)
(14)
(446)
(104)
(765)
(1)
(2)
(399)
(76)
(478)
(23)
(1)
(363)
(51)
(438)
Financial statements
$ million
2020
Total
(694)
(1,093)
(5,489)
(1,037)
(8,313)
$ million
2019
Total
(744)
(1,478)
(4,871)
(952)
(8,045)
Over
5 years
(63)
—
(2,550)
(233)
(2,846)
Over
5 years
(70)
—
(2,071)
(161)
(2,302)
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of
fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Less than
1 year
48
3,342
739
4,129
(1,182)
2,947
(55)
(3,577)
(492)
(4,124)
1,182
(2,942)
5
Less than
1 year
63
5,344
779
6,186
(2,041)
4,145
(49)
(4,522)
(506)
(5,077)
2,041
(3,036)
1,109
1-2 years
2-3 years
3-4 years
4-5 years
9
858
546
1,413
(253)
1,160
(9)
(809)
(414)
(1,232)
253
(979)
181
15
367
552
934
(77)
857
(13)
(263)
(426)
(702)
77
(625)
232
3
212
520
735
(38)
697
(3)
(136)
(404)
(543)
38
(505)
192
5
100
493
598
(37)
561
(5)
(41)
(407)
(453)
37
(416)
145
1-2 years
2-3 years
3-4 years
4-5 years
6
1,014
501
1,521
(291)
1,230
(8)
(932)
(377)
(1,317)
291
(1,026)
204
2
439
485
926
(80)
846
(4)
(458)
(383)
(845)
80
(765)
81
—
210
540
750
(36)
714
(1)
(146)
(367)
(514)
36
(478)
236
2
120
452
574
(29)
545
(2)
(113)
(352)
(467)
29
(438)
107
$ million
2020
Total
81
5,588
6,398
12,067
(2,019)
10,048
(86)
(4,905)
(5,341)
(10,332)
2,019
(8,313)
1,735
$ million
2019
Total
74
7,169
5,465
12,708
(2,724)
9,984
(65)
(6,272)
(4,432)
(10,769)
2,724
(8,045)
1,939
Over
5 years
1
709
3,548
4,258
(432)
3,826
(1)
(79)
(3,198)
(3,278)
432
(2,846)
980
Over
5 years
1
42
2,708
2,751
(247)
2,504
(1)
(101)
(2,447)
(2,549)
247
(2,302)
202
bp Annual Report and Form 20-F 2020
213
30. Derivative financial instruments – continued
Level 3 derivatives
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value
hierarchy.
Fair value contracts at 1 January 2020
Gains (losses) recognized in the income statement
Sales
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2020
Deferred day-one gains (losses)
Derivative asset (liability)
Fair value contracts at 1 January 2019
Gains (losses) recognized in the income statement
Gains (losses) recognized in other comprehensive income
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2019
Deferred day-one gains (losses)
Derivative asset (liability)
Oil
price
71
250
—
(135)
5
191
Natural gas
price
28
184
—
(22)
(43)
147
Power
price
(125)
162
—
(189)
(21)
(173)
Currency and
other
110
(66)
(32)
—
(1)
11
Oil
price
23
128
—
(79)
(1)
71
Natural gas
price
(13)
82
—
(21)
(20)
28
Power
price
(148)
244
(18)
(179)
(24)
(125)
Other
107
2
—
—
1
110
$ million
Total
84
530
(32)
(346)
(60)
176
881
1,057
$ million
Total
(31)
456
(18)
(279)
(44)
84
949
1,033
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2020 was a $315-
million gain (2019 $250-million gain related to derivatives still held at 31 December 2019).
Derivative gains and losses
The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating to both
currency and commodity trading activities. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and
entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be
fair valued under accounting standards. These gains and losses are included within sales and other operating revenues in the income statement. Also
included within this line item are gains and losses on inventory held for trading purposes. The total amount relating to all these items was a net gain of
$2,808 million. This number does not include gains and losses on the change in value of contracts which are not recognized under IFRS such as
transportation and storage contracts, but does include the associated financially settled contracts. The net amounts for actual gains and losses relating
to these derivative contracts and all related items therefore differ significantly from the amounts disclosed above.
The group also enters into derivative contracts relating to foreign currency risk management activities including contracts that the group has entered
into to manage the foreign currency exposure relating to the non-US dollar hybrid bonds to their respective first call periods. Gains and losses on these
contracts are included within production and manufacturing expenses in the income statement. The change in the unrealized value of these contracts
was a net gain of $829 million (2019 $160 million net gain and 2018 $351 million net loss), however where these gains and losses arise on derivatives
hedging finance debt they are largely offset by opposing net foreign exchange differences on retranslation of the associated non-US dollar debt. The net
amounts for actual gains and losses relating to these derivative contracts and all related items therefore differ significantly from the amounts disclosed
above.
Cash flow hedges
(i) Foreign currency risk of highly probable forecast capital expenditure
At 31 December 2020, the group held currency forwards designated as hedging instruments in cash flow hedge relationships of highly probable
forecast non-US dollar capital expenditure. Note 29 outlines the group’s approach to foreign currency exchange risk management. When the highly
probable forecast capital expenditure designated as a hedged item occurs, a non-financial asset is recognized and is presented within the fixed asset
section of the balance sheet.
The group claims hedge accounting only for the spot value of the currency exposure in line with the strategy to fix the volatility in the spot exchange
rate element. The fair value on the instrument attributable to forward points and foreign currency basis spreads is taken immediately to the income
statement.
The group applies hedge accounting where there is an economic relationship between the hedged item and hedging instrument. The existence of an
economic relationship is determined at inception and prospectively by comparing the critical terms of the hedging instrument and those of the hedged
item. The group enters into hedging derivatives that match the currency and notional of the hedged items on a 1:1 hedge ratio basis. The hedge ratio is
determined by comparing the notional amount of the derivative with the notional designated on the forecast transaction. The group determines the
extent to which it hedges highly probable forecast capital expenditures on a project by project basis.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
• counterparty's credit risk, the group mitigates counterparty credit risk by entering into derivative transactions with high credit quality counterparties;
and
214
bp Annual Report and Form 20-F 2020
Financial statements
30. Derivative financial instruments – continued
• differences in settlement timing between the derivative and hedged items. The latter impacts the discount factor used in the calculation of the hedge
ineffectiveness. The group mitigates differences in timing between the derivatives and hedged items by applying a rolling strategy and by hedging
currency pairs from stable economies (i.e. sterling/US dollar, Korean won/US dollar). The group's cash flow hedge designations are highly effective as
the sources of ineffectiveness identified are expected to result in minimal hedge ineffectiveness.
The group has not designated any net positions as hedged items in cash flow hedges of foreign currency risk.
(ii) Commodity price risk of highly probable forecast sales
During the period the group held Henry Hub NYMEX futures designated as hedging instruments in cash flow hedge relationships of certain highly
probable forecast future sales. Henry Hub NYMEX futures are subject to daily settlement, where their fair value at the end of each day is required to be
cash settled, such that the carrying amount of these hedging instruments within continuing hedge relationships is always zero at the end of each day.
The group is exposed to the variability in the gas price, but only applied hedge accounting to the risk of Henry Hub price movements for a percentage of
future gas sales from its BPX Energy business.
The group applied hedge accounting in relation to these highly probable future sales where there was an economic relationship between the hedged
item and hedging instrument. The existence of an economic relationship was determined at inception and prospectively by comparing the critical terms
of the hedging instrument and those of the hedged item. The group entered into hedging derivatives that matched the notional amounts of the hedged
items on a 1:1 hedge ratio basis. The hedge ratio was determined by comparing the notional amount of the derivative with the notional amount
designated on the forecast transaction.
The hedge was highly effective due to the price index of the hedging instruments matching the price index of the hedged item. The group did not
designate any net positions as hedged items in cash flow hedges of commodity price risk.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period.
At 31 December 2020
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
Commodity price risk
Highly probable forecast sales
At 31 December 2019
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
Commodity price risk
Highly probable forecast sales
$ million
Change in fair
value of
hedging
instrument
used to
calculate
ineffectiveness
Change in fair
value of
hedged item
used to
calculate
ineffectiveness
Hedge
ineffectiveness
recognized in
profit or (loss)
4
(4)
78
(78)
(1)
1
(100)
100
—
—
—
—
The tables below summarize the carrying amount and nominal amount of the derivatives designated as hedging instruments in cash flow hedge
relationships.
At 31 December 2020
Cash flow hedges
Foreign exchange risk
Highly probable forecast capital expenditure
Commodity price risk
Highly probable forecast sales
At 31 December 2019
Cash flow hedges
Foreign exchange risk
Carrying amount of hedging
instrument
Assets
Liabilities
Nominal amounts of hedging
instruments
$ million
$ million
$ million
mmBtu
4
—
—
162
—
(175)
Highly probable forecast capital expenditure
1
(4)
150
All hedging instruments are presented within derivative financial instruments on the group balance sheet.
All of the nominal amount of hedging instruments at 31 December 2020 and 2019 relating to highly probably forecast capital expenditure matures
within 12 months of the relevant balance sheet date. Of the nominal amount of hedging instruments at 31 December 2020 relating to highly probably
forecast sales 135 mmBtu matures within 12 months and 40 mmBtu within one to two years.
bp Annual Report and Form 20-F 2020
215
30. Derivative financial instruments – continued
The table below summarizes the weighted average exchange rates and the weighted average sales price in relation to the derivatives designated as
hedging instruments in cash flow hedge relationships at 31 December.
At 31 December
Sterling/US dollar
Euro/US dollar
Korean won/US dollar
Henry Hub $/mmBtu
Weighted average price/rate
2020
2019
Forecast capital
expenditure
1.35
—
1,174.47
Forecast capital
expenditure
1.35
1.11
1,115.66
Forecast sales
2.88
Fair value hedges
At 31 December 2020, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk and
foreign currency risk arising from group fixed rate debt issuances. Note 29 outlines the group’s approach to interest rate and foreign currency exchange
risk management. The interest rate swaps are used to convert US dollar denominated fixed rate borrowings into floating rate debt. The cross-currency
interest rate swaps are used to convert sterling, euro, Swiss franc, Canadian dollar and Norwegian krone denominated fixed rate borrowings into US
dollar floating rate debt. The group manages all risks derived from debt issuance, such as credit risk, however, the group applies hedge accounting only
to certain components of interest rate and foreign currency risk in order to minimize hedge ineffectiveness. The interest rate and foreign currency
exposures are identified and hedged on an instrument-by-instrument basis. For interest rate exposures, the group designates as a fair value hedge the
benchmark interest rate component only. This is an observable and reliably measurable component of interest rate risk.
All of the fair value hedge accounting relationships currently in place are directly affected by the interest rate benchmark reform which will replace
interbank offered rates (IBORs) with alternative benchmark rates as they all manage interest rate risk. The Group is significantly exposed to benchmark
interest rate components; predominantly USD LIBOR, GBP LIBOR, EURIBOR and CHF LIBOR. The nominal amounts of the applicable hedging
instruments represent the extent of the risk exposure bp manages for financial derivatives designated in fair value hedge relationships that is directly
affected by the interest rate benchmark reform. These are disclosed in the table below. Uncertainty around the method and timing of transition from
Inter-bank Offered Rates (IBORs) to alternative risk-free rates (RfRs) may impact the assessment of whether hedge accounting can be applied to
certain hedging relationships. However, the temporary reliefs provided by IFRS 9 allow bp to assume that in the event that significant uncertainty
around the reform arises:
• the interest rate benchmark component of fair value hedges only needs to be assessed as separately identifiable at initial designation; and
• the interest rate benchmark is not altered for the purposes of assessing the economic relationship between the hedged item and the hedging
instrument for fair value hedges.
Judgement will be required to determine when the uncertainty arising from interest rate benchmark reform is no longer present and when the
temporary reliefs no longer apply. However, at 31 December 2020 the reliefs apply and bp continues to monitor regulatory and market developments
as it manages the contractual transition.
For foreign currency exposures, the group excludes from the designation the foreign currency basis spread component implicit in the cross-currency
interest rate swaps. This is separately calculated at hedge designation, is recognized in other comprehensive income over the life of the hedge and
amortized to the income statement on a straight-line basis, in accordance with the group’s policy on costs of hedging.
The group applies hedge accounting where there is an economic relationship between the hedged item and the hedging instrument. The existence of
an economic relationship is determined initially by comparing the critical terms of the hedging instrument and those of the hedged item and it is
prospectively assessed using linear regression analysis. The group issues fixed rate debt and enters into interest rate and cross-currency interest rate
swaps with critical terms that match those of the debt and on a 1:1 hedge ratio basis. The hedge ratio is determined by comparing the notional amount
of the derivative with the notional amount of the debt. The hedge relationship is designated for the full term and notional value of the debt. Both the
hedging instrument and the hedged item are expected to be held to maturity.
The group has identified the following sources of ineffectiveness, which are not expected to be material:
• derivative counterparty’s credit risk which is not offset by the hedged item. This risk is mitigated by entering into derivative transactions only with
high credit quality counterparties; and
• sensitivity to interest rate between the hedged item and the derivatives. This is driven by differences in payment frequencies between the
instrument and the bond.
The tables below summarize the change in the fair value of hedging instruments and the hedged item used to calculate ineffectiveness in the period.
The signage convention for changes in fair value presented in this table is consistent with that presented in Note 27.
At 31 December 2020
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
216
bp Annual Report and Form 20-F 2020
$ million
Change in fair
value of hedging
instrument used
to calculate
ineffectiveness
Change in fair
value of hedged
item used to
calculate
ineffectiveness
Hedge
ineffectiveness
recognized in
profit or (loss)
(258)
(2,743)
258
2,549
(764)
(336)
737
286
—
194
27
50
30. Derivative financial instruments – continued
The tables below summarize the carrying amount of the derivatives designated as hedging instruments in fair value hedge relationships at 31
December.
Financial statements
At 31 December 2020
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
Carrying amount of hedging
instrument
Assets
Liabilities
$ million
Nominal
amounts of
hedging
instruments
80
2,614
—
(82)
4,104
23,313
138
344
(35)
(637)
13,442
21,296
All hedging instruments are presented within derivative financial instruments on the group balance sheet. Ineffectiveness arising on fair value hedges is
included within the production and manufacturing expenses section of the income statement.
The tables below summarize the profile by tenor of the nominal amount of the derivatives designated as hedging instruments in fair value hedge
relationships at 31 December.
At 31 December 2020
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on
finance debt
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on
finance debt
Less than 1
year
1-2 years
2-3 years
3-4 years
4-5 years
5-10 years Over 10 years
Total
$ million
2,705
996
—
227
—
176
—
4,104
737
1,056
2,039
3,175
2,804
8,587
4,915
23,313
3,000
2,576
4,039
1,200
206
2,421
—
13,442
882
672
1,400
2,777
3,109
10,216
2,240
21,296
The table below summarizes the weighted average floating interest rate and the weighted average exchange rates in relation to the derivatives
designated as hedging instruments in fair value hedge relationships at 31 December.
At 31 December
Interest rate
Sterling/US dollar
Euro/US dollar
Canadian dollar/US dollar
Interest rate
swaps
0.58 %
2020
Cross-currency
interest rate
swaps
1.88 %
1.33
1.14
0.78
Interest rate
swaps
2.36 %
2019
Cross-currency
interest rate
swaps
3.27 %
1.32
1.15
0.87
The tables below summarize the carrying amount, and the accumulated fair value adjustments included within the carrying amount, of the hedged
items designated in fair value hedge relationships at 31 December.
At 31 December 2020
Fair value hedges
Carrying amount of hedged item
Accumulated fair value adjustment included in the
carrying amount of hedged items
$ million
Assets
Liabilities
Assets
Liabilities
Discontinued
hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
—
—
(4,196)
(23,253)
—
—
(81)
(938)
(775)
—
At 31 December 2019
Fair value hedges
Interest rate risk on finance debt
Interest rate and foreign currency risk on finance debt
—
—
(13,441)
(21,240)
—
—
(100)
(525)
(714)
—
The hedged item for all fair value hedges is presented within finance debt on the group balance sheet.
bp Annual Report and Form 20-F 2020
217
30. Derivative financial instruments – continued
Movement in reserves related to hedge accounting
The table below provides a reconciliation of the cash flow hedge and costs of hedging reserves on a pre-tax basis by risk category. The signage
convention of this table is consistent with that presented in Note 32.
Cash flow hedge reserve
Costs of
hedging
reserve
At 1 January 2020
Recognized in other comprehensive income
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement - hedged item
affected profit or loss
Costs of hedging marked to market
Costs of hedging reclassified to the income statement
Cash flow hedges transferred to the balance sheet
At 31 December 2020
Highly
probable
forecast capital
expenditure
Highly
probable
forecast sales
(1)
7
—
—
—
7
6
12
—
78
(37)
—
—
41
—
41
Interest rate
and foreign
currency risk
on finance debt
Purchase of
equitya
(651)
(170)
—
—
42
22
64
—
—
—
—
—
—
—
$ million
Total
(822)
85
(37)
42
22
112
6
(651)
(106)
(704)
$ million
At 1 January 2019
Recognized in other comprehensive income
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement - hedged item
affected profit or loss
Costs of hedging marked to market
Costs of hedging reclassified to the income statement
Cash flow hedges transferred to the balance sheet
Cash flow hedge reserve
Costs of
hedging reserve
Highly probable
forecast capital
expenditure
Highly probable
forecast sales
(21)
(6)
Interest rate and
foreign currency
risk on finance
debt
(223)
Purchase of
equitya
(651)
Total
(901)
(3)
(100)
—
—
—
(3)
23
106
—
—
6
—
—
—
—
—
—
—
—
(103)
—
(4)
57
53
—
106
(4)
57
56
23
At 31 December 2019
a See Note 32 for further information on the cash flow hedge reserve relating to the purchase of equity.
Substantially all of the cash flow hedge reserve balances and all of the amounts reclassified from the cash flow hedge reserve into profit or loss during
the year relate to continuing hedge relationships. Amounts deferred in the cash flow hedge reserve that have been reclassified to profit or loss are
presented in sales and other operating revenues in the income statement.
(651)
(170)
—
(1)
(822)
Costs of hedging relates to the foreign currency basis spreads of hedging instruments used to hedge the group's interest rate and foreign currency risk
on debt which is a time-period related item.
218
bp Annual Report and Form 20-F 2020
Financial statements
31. Called-up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
Issued
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share-based payment plans
Issue of new shares – other
Repurchase of ordinary share capital
At 31 December
Shares
thousand
7,233
5,473
2020
$ million
12
9
21
Shares
thousand
7,233
5,473
2019
$ million
12
9
21
Shares
thousand
7,233
5,473
21,535,840
—
34,000
—
(120,058)
21,449,782
—
9
—
(30)
5,383 21,525,464
208,927
37,400
—
(235,951)
5,362 21,535,840
5,383
52
9
—
(59)
5,381 21,288,193
195,305
92,168
—
(50,202)
5,383 21,525,464
5,404
2018
$ million
12
9
21
5,322
49
23
—
(13)
5,381
5,402
a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference
shares.
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for
every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on
other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference
shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the
preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over
par value.
During 2020 the company repurchased 120 million ordinary shares for a total consideration of $776 million, including transaction costs of $4 million, as
part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares
represented 0.6% of ordinary share capital. The number of shares in issue is reduced when shares are repurchased.
Treasury sharesa
2020
2019
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
Shares
thousand
At 1 January
Purchases for settlement of employee share plans
Issue of new shares for employee share-based payment plans
Shares re-issued for employee share-based payment plans
At 31 December
Of which – shares held in treasury by bp
– shares held in ESOP trusts
– shares held by bp’s US share plan administratorb
1,296,856
—
34,116
(143,322)
1,187,650
1,105,157
82,491
2
a See Note 32 for definition of treasury shares.
b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
323 1,426,265
1,118
—
37,400
9
(36)
(167,927)
296 1,296,856
275 1,163,077
133,707
72
21
—
356 1,482,072
757
—
92,168
9
(42)
(148,732)
323 1,426,265
290 1,264,732
161,518
15
33
—
2018
Nominal value
$ million
370
—
23
(37)
356
316
40
—
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by bp during the year, representing 5.4%
(2019 5.9% and 2018 6.9%) of the called-up ordinary share capital of the company.
During 2020, the movement in shares held in treasury by bp represented less than 0.3% (2019 less than 0.5% and 2018 less than 1.0%) of the ordinary
share capital of the company.
bp Annual Report and Form 20-F 2020
219
32. Capital and reserves
At 1 January 2020
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges and costs of hedging (including reclassifications)
Share of items relating to equity-accounted entities, net of taxa
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Total comprehensive income
Dividends
Cash flow hedges transferred to the balance sheet, net of tax
Repurchases of ordinary share capital
Share-based payments, net of taxb
Share of equity-accounted entities’ changes in equity, net of taxc
Issue of perpetual hybrid bonds
Payments on perpetual hybrid bonds
Tax on issue of perpetual hybrid bonds
Transactions involving non-controlling interests, net of taxd
At 31 December 2020
At 31 December 2018
Adjustment on adoption of IFRS 16, net of tax
At 1 January 2019
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges and costs of hedging (including reclassifications)
Share of items relating to equity-accounted entities, net of taxa
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Share
capital
Share
premium
account
5,404 12,417
—
—
Merger
reserve
Capital
redemption
reserve
1,498 27,206
—
—
Total
share capital
and capital
reserves
46,525
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(30)
167
9
—
—
—
—
—
—
—
—
—
—
5,383 12,584
5,402 12,305
—
—
5,402 12,305
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,528 27,206
—
1,439 27,206
—
1,439 27,206
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(52)
52
—
—
—
(59)
164
9
—
—
—
—
5,404 12,417
—
—
—
—
—
59
—
—
—
—
—
—
—
—
—
—
—
—
1,498 27,206
—
—
—
—
—
—
—
—
—
—
176
—
—
—
—
—
46,701
46,352
—
46,352
—
—
—
—
—
—
—
—
—
—
—
173
—
—
46,525
Total comprehensive income
Dividends
Cash flow hedges transferred to the balance sheet, net of tax
Repurchases of ordinary share capital
Share-based payments, net of taxb
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests, net of taxe
At 31 December 2019
a Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
c Principally relates to a non-controlling interest transaction entered into by Rosneft.
d Principally relates to the sale of interests in our UK and New Zealand retail property portfolio, for which proceeds of $0.5 billion and $0.2 billion were received respectively.
e Principally relates to the sale of a 49% interest in bp's retail property portfolio in Australia.
220
bp Annual Report and Form 20-F 2020
32. Capital and reserves – continued
Financial statements
Treasury
shares
(14,412)
—
Foreign
currency
translation
reserve
(6,495)
—
—
—
—
—
—
—
—
—
—
—
1,188
—
—
—
—
—
(13,224)
(15,767)
—
(15,767)
—
—
—
—
—
—
—
—
—
—
—
1,355
—
—
(14,412)
(2,224)
—
—
—
—
—
(2,224)
—
—
—
—
—
—
—
—
—
(8,719)
(8,902)
—
(8,902)
—
2,407
—
—
—
—
—
2,407
—
—
—
—
—
—
(6,495)
Available-
for-sale
investments
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Cash flow
hedges
(752)
—
Costs of
hedging
(160)
—
Total
fair value
reserves
(912)
—
Profit and
loss
account
73,706
(20,305)
bp
shareholders’
equity
98,412
(20,305)
Hybrid bonds Other interest
—
256
2,296
(680)
Total equity
100,708
(20,729)
Non-controlling interests
$ million
—
31
—
—
—
7
38
—
6
—
—
—
—
—
—
—
(708)
(777)
—
(777)
—
—
5
—
—
—
(3)
2
—
23
—
—
—
—
(752)
—
60
—
—
—
—
60
—
—
—
—
—
—
—
—
—
(100)
(210)
—
(210)
—
—
50
—
—
—
—
50
—
—
—
—
—
—
(160)
—
91
—
—
—
7
98
—
6
—
—
—
—
—
—
—
(808)
(987)
—
(987)
—
—
55
—
—
—
(3)
52
—
23
—
—
—
—
(912)
—
—
312
71
65
—
(19,857)
(6,367)
—
(776)
(638)
1,341
(48)
—
3
(64)
47,300
78,748
(329)
78,419
4,026
—
—
82
(64)
171
—
4,215
(6,929)
—
(1,511)
(809)
5
316
73,706
(2,224)
91
312
71
65
7
(21,983)
(6,367)
6
(776)
726
1,341
(48)
—
3
(64)
71,250
99,444
(329)
99,115
4,026
2,407
55
82
(64)
171
(3)
6,674
(6,929)
23
(1,511)
719
5
316
98,412
—
—
—
—
—
—
256
—
—
—
—
—
11,909
(89)
—
—
12,076
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
37
—
—
—
—
—
(643)
(238)
—
—
—
—
—
—
—
827
2,242
2,104
(1)
2,103
164
9
—
—
—
—
—
173
(213)
—
—
—
—
233
2,296
(2,187)
91
312
71
65
7
(22,370)
(6,605)
6
(776)
726
1,341
11,861
(89)
3
763
85,568
101,548
(330)
101,218
4,190
2,416
55
82
(64)
171
(3)
6,847
(7,142)
23
(1,511)
719
5
549
100,708
bp Annual Report and Form 20-F 2020
221
Merger
reserve
Capital
redemption
reserve
1,426 27,206
—
1,426 27,206
—
—
—
Total
share capital
and capital
reserves
46,122
—
46,122
—
—
—
—
—
—
—
—
—
—
—
—
—
—
13
—
—
—
—
—
—
—
—
—
—
—
—
1,439 27,206
—
—
—
—
—
—
—
—
—
—
230
—
—
46,352
32. Capital and reserves – continued
At 31 December 2017
Adjustment on adoption of IFRS 9, net of tax
At 1 January 2018
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges and costs of hedging (including reclassifications)
Share of items relating to equity-accounted entities, net of taxa
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Total comprehensive income
Dividends
Cash flow hedges transferred to the balance sheet, net of tax
Repurchases of ordinary share capital
Share-based payments, net of taxb
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests, net of tax
At 31 December 2018
a Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
Share
capital
Share
premium
account
5,343 12,147
—
—
5,343 12,147
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(49)
49
—
—
—
(13)
207
23
—
—
—
—
5,402 12,305
222
bp Annual Report and Form 20-F 2020
Financial statements
32. Capital and reserves – continued
Treasury
shares
(16,958)
—
(16,958)
—
—
—
—
—
—
—
—
—
—
—
1,191
—
—
(15,767)
Foreign
currency
translation
reserve
(5,156)
—
(5,156)
—
(3,746)
—
—
—
—
—
(3,746)
—
—
—
—
—
—
(8,902)
Available-
for-sale
investments
17
(17)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Cash flow
hedges
(760)
—
(760)
—
—
(6)
—
—
—
(37)
(43)
—
26
—
—
—
—
(777)
Costs of
hedging
Total
fair value
reserves
—
(37)
(37)
—
—
(173)
—
—
—
—
(173)
—
—
—
—
—
—
(210)
(743)
(54)
(797)
—
—
(179)
—
—
—
(37)
(216)
—
26
—
—
—
—
(987)
Profit and
loss
account
75,226
(126)
75,100
9,383
bp
shareholders’
equity
98,491
(180)
98,311
9,383
—
—
417
7
1,599
—
11,406
(6,699)
—
(355)
(718)
14
—
78,748
(3,746)
(179)
417
7
1,599
(37)
7,444
(6,699)
26
(355)
703
14
—
99,444
Non-controlling interests
Hybrid bonds
Other interest
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,913
—
1,913
195
(41)
—
—
—
—
—
154
(170)
—
—
—
—
207
2,104
$ million
Total equity
100,404
(180)
100,224
9,578
(3,787)
(179)
417
7
1,599
(37)
7,598
(6,869)
26
(355)
703
14
207
101,548
.
bp Annual Report and Form 20-F 2020
223
32. Capital and reserves – continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury
shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in
an acquisition made by the issue of shares.
Treasury shares
Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes shares held in Employee
Share Ownership Plans (ESOPs) and bp’s US share plan administrator to meet the future requirements of the employee share-based payment plans are
treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by the
group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the ESOPs vest
unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the ESOPs are
recognized as assets and liabilities of the group.
Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations.
Upon disposal of foreign operations, the related accumulated exchange differences are reclassified to the income statement.
Available-for-sale investments
This reserve recorded the changes in fair value of investments classified as available-for-sale under IAS 39 except for impairment losses, foreign
exchange gains or losses, or changes arising from revised estimates of future cash flows. On adoption of IFRS 9 the balance in this reserve was
transferred to the profit and loss account reserve. Under the new standard the group recognizes fair value gains and losses on these investments in
profit or loss.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. It
includes $651 million relating to the acquisition of an 18.5% interest in Rosneft in 2013 which will only be reclassified to the income statement if the
investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges see Note 1 - Derivative financial
instruments and hedging activities.
Costs of hedging
This reserve records the change in fair value of the foreign currency basis spread of financial instruments to which cost of hedge accounting has been
applied. The accumulated amount relates to time-period related hedged items and is amortized to profit or loss over the term of the hedging
relationship.
Prior to the group’s adoption of IFRS 9 changes in the fair value of such foreign currency basis spreads were recognized in profit or loss. On adoption of
the new standard a transfer from the profit and loss account reserve to the costs of hedging reserve was made in order to reflect the opening reserves
position for relevant hedging instruments existing on transition. For further information on the accounting for costs of hedging see Note 1 - Derivative
financial instruments and hedging activities.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
Non-controlling interests
Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to bp shareholders. Included within non-
controlling interests are perpetual subordinated hybrid bonds issued by BP Capital Markets PLC, a group subsidiary, on 17 June 2020 in euro, sterling
and US dollars for a US dollar equivalent amount of $11.9 billion. The hybrid bonds include redemption options exercisable at the group’s discretion
from June 2025 to March 2030 (the first ‘call date’), on specified dates thereafter, or in the event of specific circumstances (such as a change in IFRS or
tax regime) as set out in the individual terms of each issue. Coupons are fixed for an initial period up to dates from September 2025 to June 2030 at
rates of 3.25% to 4.875% and reset to rates determined by the contractual terms of each instrument on certain dates thereafter. The contractual terms
of the hybrid bonds allow the group to defer coupon payments and the repayment of principal indefinitely, however their terms and conditions stipulate
that any deferred payments must be made in the event of an announcement of an ordinary share or parity equity dividend distribution or certain share
repurchases or redemptions. As the group has the unconditional right to avoid transferring cash or another financial asset in relation to these hybrid
bonds, they are classified as equity instruments and reported within non-controlling interests in the consolidated financial statements.
224
bp Annual Report and Form 20-F 2020
32. Capital and reserves – continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
Financial statements
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges (including reclassifications)
Costs of hedging (including reclassifications)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges (including reclassifications)
Costs of hedging (including reclassifications)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including reclassifications)
Cash flow hedges (including reclassifications)
Costs of hedging (including reclassifications)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Cash flow hedges that will subsequently be transferred to the balance sheet
Other comprehensive income
33. Contingent liabilities and legal proceedings
Pre-tax
Tax
Net of tax
$ million
2020
(2,196)
41
64
312
—
170
7
(1,602)
9
(10)
(4)
—
71
(105)
—
(39)
(2,187)
31
60
312
71
65
7
(1,641)
$ million
2019
Pre-tax
Tax
Net of tax
2,418
6
53
82
—
328
(3)
2,884
(2)
(1)
(3)
—
(64)
(157)
—
(227)
2,416
5
50
82
(64)
171
(3)
2,657
$ million
2018
Pre-tax
Tax
Net of tax
(3,771)
(6)
(186)
417
—
2,317
(37)
(1,266)
(16)
—
13
—
7
(718)
—
(714)
(3,787)
(6)
(173)
417
7
1,599
(37)
(1,980)
Contingent liabilities
There were contingent liabilities at 31 December 2020 in respect of guarantees and indemnities entered into as part of the ordinary course of the
group’s business. No material losses are likely to arise from such contingent liabilities. Further information on financial guarantees is included in Note
29.
In the normal course of the group’s business, bp group entities are subject to legal and regulatory proceedings arising out of current and past
operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer
protection, general health, safety, climate change and environmental claims and allegations of exposures of third parties to toxic substances, such as
lead pigment in paint, asbestos and other chemicals. The amounts claimed could be significant and could be material to the group’s results of
operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp expects that the impact of current legal
and regulatory proceedings on the group‘s results of operations, liquidity or financial position will not be material.
The group files tax returns in many jurisdictions across the world. Various tax authorities are currently examining these returns, which contain matters
that could be subject to differing interpretations of applicable tax laws and regulations. The resolution of tax positions through negotiations with relevant
tax authorities, or through litigation, can take several years to complete and the amounts could be significant and could, in aggregate, be material to the
group’s results of operations, financial position or liquidity. While it is difficult to predict the ultimate outcome in some cases, bp does not expect there
to be any material impact upon the group‘s results of operations, financial position or liquidity.
bp Annual Report and Form 20-F 2020
225
33. Contingent liabilities and legal proceedings – continued
The group is subject to numerous national and local health, safety and environmental laws and regulations concerning its products, operations and other
activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or
release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries,
chemical plants, oil fields, commodities extraction sites, service stations, terminals and waste disposal sites. In addition, the group may have
obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its costs are inherently difficult to estimate.
However, the estimated cost of environmental obligations has been provided in these accounts in accordance with the group‘s accounting policies.
While the amounts of future possible costs that are not provided for could be significant and material to the group‘s results of operations in the period
in which they are recognized, it is not possible to estimate the amounts involved. bp does not expect these costs to have a material impact on the
group’s results of operations, financial position or liquidity.
If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to meet their decommissioning
obligations it is possible that, in certain circumstances, bp could be partially or wholly responsible for decommissioning. While the amounts associated
with decommissioning provisions reverting to the group could be significant and could be material, bp is not currently aware of any such material cases
that have a greater than remote chance of reverting to the group. In one current case in the US, the owner of facilities has filed for bankruptcy and
submitted a proposed restructuring plan. It is considered possible that certain decommissioning costs associated with some of these facilities may in
the future revert to bp in relation to assets previously disposed. No provision has been recognised and no reliable estimate of this potential exposure is
available, however any amount which may revert is not expected to have a material impact on the group’s financial position. Furthermore, as described
in Provisions and contingencies within Note 1, decommissioning provisions associated with downstream facilities are not generally recognized as the
potential obligations cannot be measured given their indeterminate settlement dates.
Contingent liabilities related to the Gulf of Mexico oil spill
For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings below. Any further outstanding Deepwater
Horizon related claims are not expected to have a material impact on the group's financial performance.
Legal proceedings
Proceedings relating to the Deepwater Horizon oil spill
Introduction
BP Exploration & Production Inc. (BPXP) was lease operator of Mississippi Canyon, Block 252 in the Gulf of Mexico, where the semi-submersible rig
Deepwater Horizon was deployed at the time of the 20 April 2010 explosion and fire and resulting oil spill (the Incident). Lawsuits and claims arising
from the Incident were brought principally in US federal and state courts. The remaining proceedings arising from the Incident are discussed below.
Economic and Property Damages Settlement
On 22 January 2021, the United States District Court for the Eastern District of Louisiana issued an order determining the completion of all claims
processing operations of the court supervised settlement programme. That settlement programme had been established to administer claims
pursuant to the Economic and Property Damages Settlement (EPD Settlement) which was entered into with the plaintiffs’ steering committee
(PSC) acting on behalf of individual and business plaintiffs in the multi-district litigation proceedings in 2012 to resolve certain economic and
property damage claims. The Court also ordered that all future issues concerning EPD Settlement claims would be considered time barred under
the settlement programme and that the claims administrator should proceed to complete post-closure administrative wind down activities.
Medical Benefits Class Action Settlement
In 2012 the Medical Benefits Class Action Settlement (Medical Settlement) was entered into with the PSC. It involves payments to qualifying class
members based on a matrix for certain Specified Physical Conditions (SPCs), as well as a 21-year Periodic Medical Consultation Program (PMCP) for
qualifying class members. As of 31 December 2020, 1 claim remained pending determination. In total, 27,603 claims (comprising 22,833 SPC claims
and 4,770 PMCP claims) have been approved for compensation totalling approximately $67 million and 9,623 claims have been denied.
The Medical Settlement also includes provisions regarding class members pursuing claims for later-manifested physical conditions (LMPCs). In
order to seek compensation from bp for an LMPC, class members must file a notice with the Medical Claims Administrator within 4 years after the
date of first diagnosis of the LMPC. As of 31 December 2020, there were 612 pending lawsuits brought by class members claiming LMPCs.
Other civil complaints – economic loss
Nearly all economic loss and property damage claims from individuals and businesses that either opted out of the EPD Settlement and/or were
excluded from that settlement have been settled or dismissed.
The claims of 10 US-resident private plaintiffs remain in the multi-district litigation proceedings in federal district court in New Orleans. Those
claims have been scheduled for a process of discovery and dispositive motions which is expected to conclude around mid-2021.
Other civil complaints – personal injury
The vast majority of post-explosion clean-up, medical monitoring and personal injury claims from individuals that either opted out of the Medical
Settlement and/or were excluded from that settlement have been dismissed.
In 2019, the federal district court in New Orleans determined in a series of proceedings that 923 plaintiffs had post-explosion clean-up, medical
monitoring and personal injury claims that complied with the court’s prior order to show cause why their claims should not be dismissed. As a
result of several subsequent dismissals, approximately 881 plaintiffs’ claims remained as of 31 December 2020.
On 23 February 2021, the district court issued a Case Management Order announcing its intent to sever the personal injury cases from the multi-
district litigation proceedings and staying the litigation of any punitive damages claims until plaintiffs can establish a right to compensatory
damages. The district court also stated that the order severing and re-allotting these cases is forthcoming. Most cases will remain in the federal
district court in New Orleans and be re-allotted among the judges of that court.
Individual securities litigation
In October 2020, bp engaged with the plaintiffs in a mediation of all remaining multi-district litigation proceedings in federal district court in
Houston. 28 such actions on behalf of 115 plaintiffs remained pending on 31 December 2020. The mediation resulted in settlements of all these
cases and settlement agreements have now been executed with all plaintiffs.
226
bp Annual Report and Form 20-F 2020
Financial statements
33. Contingent liabilities and legal proceedings – continued
Canadian class actions
Following various legal proceedings, a plaintiff seeking to assert claims under Canadian law against bp on behalf of a class of Canadian residents who
allegedly suffered losses because of their purchase of bp ordinary shares and ADSs appealed the motion to dismiss the case in its entirety granted on 8
November 2019. On 20 January 2021, the Court of Appeal affirmed that dismissal.
Non-US government lawsuits
On 18 October 2012, before a Mexican Federal District Court located in Mexico City, a class action complaint was filed against BP America Production
Company (BPAPC) and other bp subsidiaries. On 27 June 2018, bp answered the complaint by seeking dismissal on various grounds including that no
oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. There has been no material development in these
proceedings during 2020 and up to the date of publication of this BP Annual Report and Form 20-F 2020 in 2021.
On 3 December 2015 and 29 March 2016, Acciones Colectivas de Sinaloa (ACS) filed two class actions (which have since been consolidated) in a
Mexican Federal District Court on behalf of several Mexican states against BPXP, BPAPC, and other purported bp subsidiaries. In these class actions,
plaintiffs seek an order requiring the bp defendants to repair the damage to the Gulf of Mexico, to pay penalties, and to compensate plaintiffs for
damage to property, to health and for economic loss. BPXP and BPAPC opposed class certification and sought dismissal, principally on the basis that no
oil reached Mexican waters or land and there was no economic or environmental harm in Mexico. The court certified the class on 25 September 2019
and bp appealed that decision including by way of constitutional challenge (amparo). The amparo action was denied on 8 October 2020 and on 18
January 2021, bp’s appeal of that ruling was also denied. Class notification procedures have not yet been finally determined.
These legal actions remain at a relatively early stage and while it is not possible to predict the outcome, bp believes that it has valid defences, and it
intends to defend such actions vigorously.
Other legal proceedings
FERC and CFTC matters
Following an investigation by the US Federal Energy Regulatory Commission (FERC) and the US Commodity Futures Trading Commission (CFTC) of
several bp entities, the Administrative Law Judge of the FERC ruled on 13 August 2015 that bp manipulated the market by selling next-day, fixed price
natural gas at Houston Ship Channel in 2008 in order to suppress the Gas Daily index and benefit its financial position. On 11 July 2016 the FERC
issued an Order affirming the initial decision and directing bp to pay a civil penalty of $20.16 million and to disgorge $207,169 in unjust profits. On 10
August 2016, bp filed a request for rehearing with the FERC. On 17 December 2020, the FERC denied the rehearing request, sustaining the prior
decision and ordering payment of the penalty and disgorgement amounts. bp has complied with the order but strongly disagrees with the FERC’s
decision and is pursuing an appeal to the US Court of Appeals.
Lead paint matters
Since 1987, Atlantic Richfield Company (Atlantic Richfield), a subsidiary« of bp, has been named as a co-defendant in numerous lawsuits brought
in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed
against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as alleged successor to International Smelting and Refining and another
company that manufactured lead pigment during the period 1920-1946. The plaintiffs include individuals and governmental entities. Several of the
lawsuits purport to be class actions. The lawsuits seek various remedies including compensation to lead-poisoned children, cost to find and remove
lead paint from buildings, medical monitoring and screening programmes, public warning and education of lead hazards, reimbursement of
government healthcare costs and special education for lead-poisoned citizens and punitive damages. No lawsuit against Atlantic Richfield has been
settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. The amounts claimed and, if such suits were
successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the
outcome of these legal actions, Atlantic Richfield believes that it has valid defences. It intends to defend such actions vigorously and believes that
the incurrence of liability is remote. Consequently, bp believes that the impact of these lawsuits on the group’s results, financial position or liquidity
will not be material.
Climate change
BP p.l.c., BP America Inc. and BP Products North America Inc. are co-defendants with other oil and gas companies in multiple lawsuits brought in
various state and federal courts on behalf of various governmental and private parties. The lawsuits generally assert claims under a variety of legal
theories seeking to hold the defendant companies responsible for impacts allegedly caused by and/or relating to climate change and seek remedies
including payment of money and other forms of equitable relief. If such suits were successful, the cost of the remedies sought in the various cases
could be substantial. All of these lawsuits remain at relatively early stages and while it is not possible to predict the outcome of these legal actions, BP
believes that it has valid defences, and it intends to defend such actions vigorously.
Louisiana Coastal restoration
Six coastal parishes and the State of Louisiana have filed over 40 separate lawsuits in state courts in Louisiana against various oil and gas companies
seeking damages for coastal erosion. bp entities are defendants in 17 of these cases. The lawsuits allege that the defendants' historical operations in
oil fields within the Louisiana onshore coastal zone failed to comply with state permits and/or were conducted without the required coastal use permits.
The plaintiffs seek unspecified statutory penalties and damages, including the costs of restoring coastal wetlands allegedly impacted by oil field
operations.
In addition, four private landowners have filed separate claims in the state courts in Jefferson and Plaquemines Parishes of Louisiana for restoration
damages related to alleged impacts to their marshlands associated with historic oil field operations. bp entities are defendants in two of these private
landowner cases.
All of these lawsuits remain at relatively early stages and while it is not possible to predict the outcome of these legal actions, bp believes that it has
valid defences, and it intends to defend such actions vigorously.
bp Annual Report and Form 20-F 2020
227
34. Remuneration of senior management and non-executive directors
Remuneration of directors
Total for all directors
Emoluments
Amounts received under incentive schemesa
Total
a Excludes amounts relating to past directors.
2020
2019
6
14
20
9
20
29
$ million
2018
8
16
24
Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits
earned during the relevant financial year, plus cash bonuses awarded for the year.
Pension contributions
During 2020 one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2020, one executive
director participated in retirement savings plans established for US employees and in a US defined benefit pension plan in respect of service prior to 1
September 2016.
Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 103. See also Related-party transactions on
page 326.
Remuneration of directors and senior management
Total for all senior management and non-executive directors
Short-term employee benefits
Pensions and other post-retirement benefits
Share-based payments
Termination benefits
Total
2020
2019
$ million
2018
17
2
52
8
79
30
2
32
—
64
25
2
32
—
59
Senior management comprises members of the leadership team, see pages 78-79 for further information.
Short-term employee benefits
These amounts comprise fees and benefits paid to the non-executive chairman and non-executive directors, as well as salary, benefits and cash
bonuses for senior management. Deferred annual bonus awards, to be settled in shares, are included in share-based payments.
Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing pensions and other post-retirement benefits to senior management in respect of
the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares
granted, accounted for in accordance with IFRS 2 ‘Share-based Payments’.
Termination benefits
Termination benefits include compensation to senior management for loss of office.
228
bp Annual Report and Form 20-F 2020
35. Employee costs and numbers
Employee costs
Wages and salariesa
Social security costs
Share-based paymentsb
Pension and other post-retirement benefit costs
Average number of employeesc
Upstream
Downstreamd
Other businesses and corporatee
Financial statements
2020
7,600
729
728
852
9,909
2019
7,497
733
694
948
9,872
$ million
2018
7,931
743
669
1,154
10,497
2020
2019
2018
US
Total
Non-US
Non-US
Total
5,900 11,500 17,400
6,000 36,300 42,300
1,900 12,100 14,000
12,400 55,700 68,100 13,600 58,900 72,500 13,800 59,900 73,700
Non-US
5,800 11,000 16,800
5,700 37,300 43,000
2,100 10,600 12,700
4,800 10,600 15,400
5,800 37,800 43,600
9,100
7,300
1,800
Total
US
US
a Includes termination costs of $1,237 million (2019 $182 million and 2018 $493 million). Reinvent bp restructuring accruals of $714 million and provisions of $428 million for employee termination
payments were held at 31 December 2020.
b The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled.
c Reported to the nearest 100.
d Includes 19,100 (2019 18,100 and 2018 17,100) service station staff.
e Includes 0 (2019 2,500 and 2018 4,000) agricultural, operational and seasonal workers in Brazil.
The reduction in the average number of employees in 2020 compared to 2019 is principally a result of the reinvent bp programme and divestment
activity.
36. Auditor’s remuneration
Fees
The audit of the company annual accountsa
The audit of accounts of subsidiaries of the company
Total audit
Audit-related assurance servicesb
Total audit and audit-related assurance services
Non-audit and other assurance services
Services relating to bp pension plans
2020
30
11
41
11
52
1
1
54
2019
32
11
43
4
47
1
1
49
$ million
2018
25
10
35
4
39
2
1
42
a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.
b Includes interim reviews and audit of internal control over financial reporting and non-statutory audit services. 2020 fees include audit fees relating to the Petrochemicals disposal.
With effect from 2018, following a competitive tender process, Deloitte LLP (Deloitte) was appointed as auditor of the Company, replacing Ernst &
Young LLP (EY).
2020 includes $0.5 million of additional fees for 2019. 2019 includes $3.6 million of additional fees for 2018. In addition to the amounts shown in the
table above, in 2018 $0.75 million of additional fees were paid to EY in respect of their audit for 2017. Auditor's remuneration is included in the income
statement within distribution and administration expenses.
Tax services (in relation to income tax, indirect tax compliance, employee tax services and tax advisory services) were $nil in all periods presented.
The audit committee has established pre-approval policies and procedures for the engagement of Deloitte to render audit and certain assurance and
other services. The audit fees payable to Deloitte were considered as part of the audit tender process in 2016 and challenged by the audit committee
through comparison with the audit pricing proposals of the other bidding firms. Changes in audit fees subsequent to the audit tender, including matters
relevant to the 2020 audit, have been reviewed and challenged by the Audit Committee, before being approved. Deloitte performed further assurance
services that were not prohibited by regulatory or other professional requirements and were pre-approved by the Committee. Deloitte is engaged for
these services when its expertise and experience of bp are important. Most of this work is of an audit-related or assurance nature.
Under SEC regulations, the remuneration of the auditor of $54 million (2019 $49 million and 2018 $42 million) is required to be presented as follows:
audit $41 million (2019 $43 million and 2018 $35 million); other audit-related $11 million (2019 $4 million and 2018 $4 million); tax $nil (2019 $nil and
2018 $nil); and all other fees $2 million (2019 $2 million and 2018 $3 million).
bp Annual Report and Form 20-F 2020
229
37. Subsidiaries, joint arrangements and associates
The more important subsidiaries and associates of the group at 31 December 2020 and the group percentage of ordinary share capital (to nearest
whole number) are set out below. There are no individually significant incorporated joint arrangements. The group's share of the assets and liabilities of
the more important unincorporated joint arrangements are held by subsidiaries listed in the table below. Those subsidiaries held directly by the parent
company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of undertakings of
the group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK,
along with the group’s annual report.
Subsidiaries
International
BP Corporate Holdings
BP Exploration Operating Company
*BP Global Investments
*BP International
BP Oil International
*Burmah Castrol
Angola
BP Exploration (Angola)
Azerbaijan
BP Exploration (Caspian Sea)
BP Exploration (Azerbaijan)
Canada
*BP Holdings Canada
Egypt
BP Exploration (Delta)
Germany
BP Europa SE
India
BP Exploration (Alpha)
Trinidad & Tobago
BP Trinidad and Tobago
UK
BP Capital Markets
US
*BP Holdings North America
Atlantic Richfield Company
BP America
BP America Production Company
BP Company North America
BP Corporation North America
BP Products North America
Standard Oil Company
BP Capital Markets America
Associates
Russia
Rosneft Oil Company
Country of
incorporation
%
Principal activities
100 England & Wales
100 England & Wales
100 England & Wales
100 England & Wales
100 England & Wales
100 Scotland
Investment holding
Exploration and production
Investment holding
Integrated oil operations
Integrated oil operations
Lubricants
100 England & Wales
Exploration and production
100 England & Wales
100 England & Wales
Exploration and production
Exploration and production
100 England & Wales
Investment holding
100 England & Wales
Exploration and production
100 Germany
Refining and marketing
100 England & Wales
Exploration and production
70 US
Exploration and production
100 England & Wales
Finance
100 England & Wales
100 US
100 US
100 US
100 US
100 US
100 US
100 US
100 US
Investment holding
Exploration and production, refining and
marketing
Finance
Country of
incorporation
%
Principal activities
19.75 Russia
Integrated oil operations
38. Condensed consolidating information on certain US subsidiaries
On June 30, 2020, bp completed the sale of all its interest in BP Exploration (Alaska) Inc., to Hilcorp Energy, and BP Exploration (Alaska) Inc. is therefore
no longer a subsidiary of BP p.l.c. Accordingly, bp is no longer presenting condensed consolidating information on BP Exploration (Alaska) Inc. as a
subsidiary issuer of registered securities pursuant to Rule 3-10 of Regulation S-X. BP p.l.c. will continue to fully and unconditionally guarantee the
payment obligations under the BP Prudhoe Bay Royalty Trust. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets
p.l.c. and BP Capital Markets America Inc., which are 100%-owned finance subsidiaries of BP p.l.c.
230
bp Annual Report and Form 20-F 2020
Financial statements
Supplementary information on oil and natural gas (unaudited)
The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved
reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements.
Oil and gas reserves – certain definitions
Unless the context indicates otherwise, the following terms have the meanings shown below:
Proved oil and gas reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates
that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the
hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)
The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any; and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain
economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well
penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas
cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data
and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection)
are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the
operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the
reasonable certainty of the engineering analysis on which the project or programme was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be
the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements,
excluding escalations based upon future conditions.
Undeveloped oil and gas reserves
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion.
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production
when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater
distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or
other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir
or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Developed oil and gas reserves
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)
(ii)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor
compared to the cost of a new well; and
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not
involving a well.
For details on bp’s proved reserves and production compliance and governance processes, see pages 312-317.
bp Annual Report and Form 20-F 2020
231
Oil and natural gas exploration and production activities
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Europe
Rest of
Europe
UK
South
America
North
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
$ million
2020
31,729
410
32,139
22,501
9,638
— 63,803 3,431 15,526 49,736 — 44,031
— 3,102 2,644 2,477 3,560 — 1,584
— 66,905 6,075 18,003 53,296 — 45,615
— 37,176 3,852 14,488 42,575 — 26,246
— 29,729 2,223 3,515 10,721 — 19,369
6,409 214,665
640 14,417
7,049 229,082
4,282 151,120
2,767 77,962
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
—
—
—
86
365
451
1
—
25
—
26
—
233
—
— 2,966
— 3,225
—
2
2
127
9
138
—
(1)
(1)
69
— —
— —
— —
1
—
16
16
265
451 1,507 — 2,222
1 2,503
519 1,675
168
Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)e
Depreciation, depletion and amortization
Net impairments and (gains) losses on sale of
businesses and fixed assets
Profit (loss) before taxationf
Allocable taxes
Results of operations
36
1,759
1,795
93
636
(22)
(130)
1,370
2,712
4,659
(2,864)
(1,344)
(1,520)
813 1,553
113
—
687
—
— 6,274
— 6,961
866 3,194
113
— 2,724 2,579 2,185 2,289
102
— 2,058
—
—
57
301
1 1,633
93
— 3,655
2 1,378
53 1,641 — 4,805
2 6,183
367
1
875
817 —
508
— —
97
44
2 1,994
421
140
117
157
678 2,459
5 1,716
6 11,843 3,941 6,234 7,764
(6) (4,882) (3,828) (5,368) (4,570)
(308)
— (1,125)
(6) (3,757) (3,146) (3,566) (4,262)
866 2,693 2,042 — 1,839
47 5,680
503
(45)
1 1,923
(46) (1,420)
(682) (1,802)
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax
Exploration and production activities –
—
—
—
43
1
42
43
992
130 7,650
173 8,685
610 5,192
277 14,809
887 20,001
42 10,280
114 5,023
695
113 2,333
335 10,586
12
— 11,873
616 40,790
271 (20,789)
(3,246)
180 (17,543)
91
subsidiaries (as above)
Midstream and other activities – subsidiariesg
Equity-accounted entitiesh
Total replacement cost profit (loss) before
interest and tax
(2,864)
(356)
—
(6) (4,882) (3,828) (5,368) (4,570)
(14)
185
44
(242)
—
31
104
(211)
(302)
17
(45)
(8)
(224)
503
(163)
224
271 (20,789)
(502)
(405)
8
—
(3,220)
69 (5,167) (3,643) (5,475) (4,826)
(277)
564
279 (21,696)
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of
joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and
transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most
significant midstream pipeline interests include the South Caucasus Pipeline, the Baku-Tbilisi-Ceyhan pipeline, the Trans Adriatic Pipeline and the Trans Anatolian Pipeline. Major LNG activities are
located in Trinidad, Indonesia and Australia.
b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes and other government take. The UK region includes a $330-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance
programme.
f Excludes the unwinding of the discount on provisions and payables amounting to $369 million which is included in finance costs in the group income statement.
g Midstream and other activities excludes inventory holding gains and losses.
h The profits of equity-accounted entities are included after interest and tax.
232
bp Annual Report and Form 20-F 2020
Oil and natural gas exploration and production activities – continued
Financial statements
$ million
2020
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russiaa
Rest of
Asia
Equity-accounted entities (bp share)
Capitalized costs at 31 Decemberb c
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
Results of operations for the year ended 31 Decemberb
Sales and other operating revenuesf
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Net impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
— 4,457
—
806
— 5,263
— 1,592
— 3,671
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
46
404
450
860
—
860
50
188
—
3
412
119
772
88
15
73
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 10,690 — 24,963
—
108 — 4,627
— 10,798 — 29,590
— 5,490 — 7,693
— 5,308 — 21,897
—
—
—
—
—
—
— —
82
— — 3,714
— — 3,796
315
15 —
393 — 2,594
408 — 6,705
—
— 1,110 —
—
— — 9,344
— 1,110 — 9,344
109
— —
—
486 — 1,387
—
216 — 4,418
—
—
236
411 — 1,532
—
5 —
—
294
108 —
— 1,226 — 7,976
(116) — 1,368
—
226
—
(41) —
(75) — 1,142
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities
Exploration and production activities – equity-
accounted entities after tax (as above)
Midstream and other activities after taxg
Total replacement cost profit (loss) after
(75) — 1,142
(242) (1,366)
73
(42)
—
17
—
—
—
—
(136)
—
224
— 40,110
— 5,541
— 45,651
— 14,775
— 30,876
—
82
— 3,714
— 3,796
376
—
— 3,391
— 7,563
— 1,970
— 9,344
— 11,314
159
—
— 2,061
— 4,634
—
244
— 2,355
—
521
— 9,974
— 1,340
200
—
— 1,140
— 1,140
— (1,545)
interest and tax
—
31
17
—
(211)
(242)
(224)
224
—
(405)
a Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and
natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
f Presented net of sales tax.
g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
bp Annual Report and Form 20-F 2020
233
Oil and natural gas exploration and production activities – continued
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
$ million
2019
31,655
425
32,080
18,481
13,599
— 67,319 3,421 15,194 48,150 — 42,629
— 3,106 2,547 3,262 3,495 — 1,865
— 70,425 5,968 18,456 51,645 — 44,494
— 35,379
409 9,922 35,572 — 22,481
— 35,046 5,559 8,534 16,073 — 22,013
6,300 214,668
606 15,306
6,906 229,974
3,924 126,168
2,982 103,806
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
2
13
15
128
717
860
5
—
50
—
55
—
271
—
— 4,047
— 4,373
Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)e
Depreciation, depletion and amortization
Net impairments and (gains) losses on sale of
businesses and fixed assets
Profit (loss) before taxationf
Allocable taxes
Results of operations
229
2,345
2,574
157
607
(75)
(308)
1,383
483
2,247
327
(141)
468
— 1,780
— 10,785
— 12,565
233
—
— 2,742
—
315
— 2,527
— 4,456
(10) 5,726
(10) 15,999
(3,434)
10
(776)
—
(2,658)
10
—
1
1
15
33
49 1,177 2,965
188
—
—
220
188
220
171
220
737 2,530 — 2,614
2 2,973
— —
18 —
18 —
2
417
1
274 1,620 2,736
2 1,588
142 2,815 — 7,596
2 9,184
275 1,762 5,551
187
2
222
124
961
437 1,045 —
951
— —
293
(124)
42
33
92
2 2,384
118 1,056 3,806
13
118
—
67
—
—
—
61
195
302
497
1,285
137 10,815
198 12,597
1,142
9,371
554 24,238
1,696 33,609
964
26
6,041
131
1,547
63
153
2,482
297 13,502
151 —
(1)
160
315 2,162 5,257
294
(400)
(40)
593
(234)
(76)
(299)
(166)
36
1
46 4,360
(44) 4,824
(8) 3,078
(36) 1,746
—
6,510
670 31,046
2,563
2,828
(265)
1,026
392
634
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax
Exploration and production activities –
subsidiaries (as above)
327
10
(3,434)
(40)
(400)
294
(44) 4,824
1,026
2,563
Midstream and other activities – subsidiariesg
Equity-accounted entitiesh
Total replacement cost profit (loss) after
interest and tax
749
(6)
(26)
70
(363)
23
442
—
194
65
(19)
11
82 2,460
766
213
9
—
1,763
2,907
1,070
54
(3,774)
402
(141)
357 2,427 5,803
1,035
7,233
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of
joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and
transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most
significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad,
Indonesia and Australia.
b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes and other government take. The UK region includes a $361-million gain which is offset by corresponding charges primarily in the US region, relating to the group self-insurance
programme.
f Excludes the unwinding of the discount on provisions and payables amounting to $439 million which is included in finance costs in the group income statement.
g Midstream and other activities excludes inventory holding gains and losses.
h The profits of equity-accounted entities are included after interest and tax.
234
bp Annual Report and Form 20-F 2020
Oil and natural gas exploration and production activities – continued
Financial statements
$ million
2019
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russiaa
Rest of
Asia
Equity-accounted entities (bp share)
Capitalized costs at 31 Decemberb c
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
— 4,078
—
768
— 4,846
— 1,046
— 3,800
—
—
—
—
—
—
—
—
—
120
640
760
Results of operations for the year ended 31 Decemberb
Sales and other operating revenuesf
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Net impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
— 1,002
—
—
— 1,002
92
—
216
—
—
—
59
—
323
—
—
—
—
—
—
—
690
312
229
83
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 10,376
—
93
— 10,469
— 5,078
— 5,391
— 28,179
— 1,097
— 29,276
— 8,477
— 20,799
—
—
—
—
—
—
—
—
—
19
675
694
—
—
58
—
58
—
177
—
— 2,908
— 3,143
— 1,621
—
—
— 1,621
43
—
465
—
343
—
16
—
414
—
—
(42)
— 1,239
382
—
245
—
137
—
—
—
— 15,012
— 15,012
73
—
— 1,386
— 7,413
—
346
— 1,657
—
46
— 10,921
— 4,091
811
—
— 3,280
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities
Exploration and production activities – equity-
accounted entities after tax (as above)
—
(6)
83
(13)
—
23
—
—
137
(72)
— 3,280
(820)
82
—
213
Midstream and other activities after taxg
Total replacement cost profit (loss) after
interest and tax
(6)
70
23
—
65
82 2,460
213
— 2,907
a Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. Amounts reported have been amended to exclude the
corresponding amounts for their equity-accounted entities.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and
natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
f Presented net of sales tax.
g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
bp Annual Report and Form 20-F 2020
235
— 42,633
— 1,958
— 44,591
— 14,601
— 29,990
—
—
58
—
58
—
316
—
— 4,223
— 4,597
— 2,623
— 15,012
— 17,635
208
—
— 2,067
— 7,756
—
421
— 2,394
—
4
— 12,850
— 4,785
— 1,285
— 3,500
— 3,500
(593)
—
Oil and natural gas exploration and production activities – continued
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
$ million
2018
29,730
451
30,181
16,809
13,372
— 89,069 3,385 14,269 51,980 — 38,315
— 3,602 2,667 2,742 3,870 — 3,153
— 92,671 6,052 17,011 55,850 — 41,468
— 47,051
420 8,517 38,324 — 20,173
— 45,620 5,632 8,494 17,526 — 21,295
6,119 232,867
568 17,053
6,687 249,920
3,626 134,920
3,061 115,000
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
1,933
—
1,933
238
817
2,988
— 10,650
—
35
— 10,685
216
—
— 3,429
— 14,330
—
—
—
139
46
185
(1) —
50 —
49 —
5
36
—
(5)
100
31
100
148
245
591 2,340 — 2,458
5 2,637
936 2,672
283
Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)e
Depreciation, depletion and amortization
Net impairments and (gains) losses on sale of
businesses and fixed assets
Profit (loss) before taxationf
Allocable taxesg
Results of operations
619
2,255
2,874
105
646
(269)
(331)
1,199
(226)
1,124
1,750
446
1,304
— 1,306
— 11,656
— 12,962
509
—
— 2,729
—
369
(2) 2,379
— 3,921
—
203
(2) 10,110
2 2,852
454
—
2 2,398
1
105 2,074 3,228 — 1,430
195 3,928 — 7,793
106 2,269 7,156 — 9,223
20
5
405
252
146
430 1,066 —
120
951
— — 1,010
357
—
94
42
165
43
133
101 1,023 3,635 — 2,165
(141) —
10
—
420 2,227 5,098
42 2,058
(314)
314 1,184
(95)
874
(272)
(219)
21
47 4,261
(47) 4,962
13 3,509
(60) 1,453
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax
Exploration and production activities –
1,750
(20)
(2)
2 2,852
188
28
265
130
(314)
(111)
—
42 2,058
(58)
5
207 2,346
(47) 4,962
463
245
135
209
subsidiaries (as above)
Midstream and other activities – subsidiariesh
Equity-accounted entitiesi j
Total replacement cost profit (loss) after
interest and tax
— 12,618
—
180
— 12,798
1,298
24
236
9,917
260 24,013
1,410 10,172
665 26,493
2,075 36,665
1,445
3
6,080
138
1,536
69
223
2,746
298 12,342
136
3
867 24,152
1,208 12,513
6,333
6,180
508
700
1,208 12,513
873
3,163
6
—
1,728
397 3,068
(425)
386 2,207 2,304 5,670
1,214 16,549
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes bp's share of oil and natural gas exploration and production activities of
joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Amounts relating to the management and ownership of crude oil and natural gas pipelines, LNG liquefaction and
transportation operations are excluded. In addition, bp's midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK, Asia and Europe are excluded. The most
significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad,
Indonesia and Australia.
b Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes, other government take and the fair value gain on embedded derivatives of $17 million. The UK region includes a $384-million gain which is offset by corresponding charges
primarily in the US region, relating to the group self-insurance programme.
f Excludes the unwinding of the discount on provisions and payables amounting to $208 million which is included in finance costs in the group income statement.
g US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017.
h Midstream and other activities excludes inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and taxes.
j From 16 December 2017, bp entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by bp and 40% by Bridas
Corporation.
236
bp Annual Report and Form 20-F 2020
Oil and natural gas exploration and production activities – continued
Financial statements
$ million
2018
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russiaa
Rest of
Asia
Equity-accounted entities (bp share)
Capitalized costs at 31 Decemberb c
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decemberb d e
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
— 3,439
—
657
— 4,096
—
670
— 3,426
—
—
—
—
—
—
—
137
137
67
251
455
Results of operations for the year ended 31 Decemberb
Sales and other operating revenuesf
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Net impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operationsg
— 1,114
—
—
— 1,114
89
—
207
—
—
—
21
—
290
—
—
—
—
—
—
6
613
501
350
151
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 9,643
—
86
— 9,729
— 4,665
— 5,064
— 22,561 3,646
—
26
811
— 23,372 3,672
— 6,050 3,672
—
— 17,322
— 39,289
— 1,580
— 40,869
— 15,057
— 25,812
—
—
—
—
—
—
—
—
—
25
575
600
393
—
148
—
541
—
179
—
— 3,085
— 3,805
— 1,792
—
—
— 1,792
7
—
438
—
361
—
55
—
416
—
—
—
— 1,277
515
—
321
—
194
—
—
—
— 14,839
— 14,839
109
—
— 1,324
— 7,168
—
594
— 1,514
—
47
— 10,756
— 4,083
814
—
— 3,269
—
—
—
—
212
212
353
—
353
—
39
94
—
212
1
346
7
—
7
393
—
285
—
678
—
271
—
— 4,123
— 5,072
— 3,259
— 14,839
— 18,098
205
—
— 2,008
— 7,623
—
670
— 2,432
—
54
— 12,992
— 5,106
— 1,485
— 3,621
— 3,621
(458)
—
— 3,163
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities
Exploration and production activities – equity-
accounted entities after tax (as above)
Midstream and other activities after taxh
Total replacement cost profit (loss) after
— 3,269
(923)
194
15
151
(21)
—
28
—
(2)
—
—
207
7
238
(2)
130
28
—
209
207 2,346
245
interest and tax
a Amounts reported for Russia in this table include bp’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The amounts reported have been amended to exclude the
corresponding amounts for their equity-accounted entities.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Amounts relating to the management and ownership of crude oil and
natural gas pipelines, LNG liquefaction, transportation operations as well as downstream and other activities are excluded.
c Costs of decommissioning are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e The amounts shown reflect bp’s share of equity-accounted entities’ costs incurred, and not the costs incurred by bp in acquiring an interest in equity-accounted entities.
f Presented net of sales taxes.
g From 16 December 2017, bp entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by bp and 40% by Bridas
Corporation.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
bp Annual Report and Form 20-F 2020
237
Movements in estimated net proved reserves
Crude oila b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberd
Developed
Undeveloped
Equity-accounted entities (bp share)e
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberf g
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
USc
Africa
Asia
Australasia
Total
Russia
Rest of
Asiac
million barrels
2020
206
200
406
(62)
—
—
—
(35)
—
(97)
162
148
309
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,063
—
842
— 1,905
40
179
218
—
—
—
—
—
—
—
(17)
24
—
2
(125)
(351)
(467)
22
—
—
—
(8)
—
14
697
—
—
742
— 1,438
37
195
232
115
35
150
(5)
10
—
—
(18)
—
(14)
112
24
136
—
—
—
—
—
—
—
—
—
—
—
—
—
—
20
20
6
—
—
—
—
—
6
5
21
26
40
198
238
42
215
258
7
5
12
—
—
—
5
—
—
5
8
9
16
291
257
548
2
—
1
17
(21)
(35)
(36)
275
237
512
298
262
560
283
246
529
156
40
196
(17)
3
—
—
(44)
—
(58)
116
21
137
— 1,074
—
525
— 1,599
26 2,572
4 1,794
30 4,367
—
—
—
—
—
—
—
175
—
—
11
(137)
—
48
14
—
—
—
(5)
—
8
114
27
—
18
(355)
(351)
(547)
— 1,100
—
547
— 1,647
34 2,154
5 1,666
38 3,819
2 3,159
— 2,535
2 5,695
1
—
—
—
1
31
—
643
238
(330)
(662)
(79)
2 3,123
— 2,493
3 5,615
—
—
—
—
—
—
—
—
—
—
—
—
1
— 3,567
— 2,847
— 6,414
—
—
—
—
—
—
—
35
10
644
255
(369)
(697)
(122)
— 3,517
— 2,776
— 6,293
158 3,159 1,074
525
198 5,695 1,599
40 2,535
26 6,140
4 4,642
30 10,781
119 3,123 1,100
548
140 5,615 1,648
22 2,493
34 5,671
5 4,441
38 10,112
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
206
200
406
115 1,063
842
150 1,905
35
At 31 December
Developed
Undeveloped
162
148
309
112
24
697
742
136 1,438
a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying
production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 37 million barrels of crude oil associated with Assets Held for Sale in Oman.
d Includes 5 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 393 million barrels of crude oil in respect of the 7.09% non-controlling interest in Rosneft, including 18.53 mmbbl held through bp's interests in Russia other than Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,533 million barrels, comprising less than 1 million barrels each in Egypt, Vietnam, Iraq and Canada, 0 million barrels in
Venezuela and 5,531 million barrels in Russia.
238
bp Annual Report and Form 20-F 2020
Movements in estimated net proved reserves – continued
Natural gas liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Financial statements
million barrels
2020
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asiac
8
5
13
(5)
—
—
—
(2)
—
(7)
7
—
7
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5
3
7
1
—
—
—
(1)
—
—
6
1
7
5
3
7
6
1
7
229
250
479
(22)
1
—
—
(31)
(94)
(146)
115
218
333
—
—
—
—
—
—
—
—
—
—
—
—
—
229
250
479
115
218
333
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
21
23
—
—
—
—
(3)
—
(2)
2
19
21
2
—
2
—
—
—
—
—
—
—
2
—
2
4
21
25
4
19
23
12
4
16
1
—
—
—
(3)
—
(2)
13
1
14
11
—
11
3
—
—
—
(2)
—
1
12
—
12
23
4
27
25
1
26
—
—
—
—
—
—
—
—
—
—
—
—
—
89
52
141
9
—
16
—
(2)
(14)
10
108
43
151
89
52
141
108
43
151
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4
—
4
(1)
—
—
—
(1)
—
(2)
2
—
2
—
—
—
—
—
—
—
—
—
—
—
—
—
4
—
4
2
—
2
255
280
535
(26)
1
—
—
(39)
(94)
(159)
139
237
376
107
55
162
12
—
16
—
(5)
(14)
10
129
44
172
363
334
697
268
281
549
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
8
5
13
At 31 December
Developed
Undeveloped
7
—
7
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 0 million barrels of NGL associated with Assets Held for Sale in Oman.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
e Includes 6 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 12 million barrels of NGLs in respect of the 7.99% non-controlling interest in Rosneft.
h Total proved NGL reserves held as part of our equity interest in Rosneft is 151 million barrels, comprising less than 1 million barrels each in Egypt, Venezuela, Vietnam and Canada, and 151 million
barrels in Russia.
bp Annual Report and Form 20-F 2020
239
Movements in estimated net proved reserves – continued
Total liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
USc
Africa
Asia
Australasia
Total
Russia
Rest of
Asiac
million barrels
2020
214
205
420
(67)
—
—
—
(37)
—
(104)
168
148
316
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,292
— 1,092
— 2,384
40
179
218
—
—
—
—
—
—
—
(40)
25
—
2
(155)
(445)
(613)
22
—
—
—
(8)
—
14
812
—
—
959
— 1,771
37
195
232
120
37
157
(4)
10
—
—
(19)
(1)
(14)
118
25
143
—
—
—
—
—
—
—
—
—
—
—
—
—
—
20
20
6
—
—
—
—
6
5
21
26
40
198
238
42
215
258
9
26
35
1
—
—
5
(3)
—
2
10
27
37
293
257
550
2
—
1
17
(21)
(35)
(36)
277
237
514
302
283
585
287
265
552
168
43
211
(16)
3
—
—
(47)
—
(60)
129
22
151
— 1,074
—
525
— 1,599
30 2,828
4 2,074
34 4,902
—
—
—
—
—
—
—
175
—
—
11
(137)
—
48
13
—
—
—
(6)
—
6
87
28
—
18
(394)
(445)
(706)
— 1,100
—
547
— 1,647
36 2,293
5 1,903
41 4,196
13 3,248
— 2,588
13 5,836
4
—
—
(2)
2
39
—
660
238
(331)
(675)
(70)
15 3,231
— 2,535
15 5,766
—
—
—
—
—
—
—
—
—
—
—
—
1
— 3,675
— 2,902
— 6,576
—
—
—
—
—
—
—
47
10
661
255
(374)
(711)
(112)
— 3,645
— 2,819
— 6,465
181 3,248 1,074
525
224 5,836 1,599
43 2,588
30 6,502
4 4,976
34 11,478
144 3,231 1,100
548
166 5,766 1,648
23 2,535
36 5,938
5 4,722
41 10,661
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
214
205
420
120 1,292
37 1,092
157 2,384
At 31 December
Developed
Undeveloped
168
148
316
118
25
812
959
143 1,771
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 37 million barrels associated with Assets Held for Sale in Oman.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
e Also includes 11 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 405 million barrels of liquids in respect of the non-controlling interest in Rosneft, including 19mmboe held through bp’s interests in Russia other than Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,683 million barrels, comprising 0 million barrels in Venezuela, less than 1 million barrels each in Iraq, Canada, Egypt and
Vietnam and 5,682 million barrels in Russia.
240
bp Annual Report and Form 20-F 2020
Movements in estimated net proved reserves – continued
Natural gasa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Financial statements
billion cubic feet
2020
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asiac
493
207
700
(252)
1
—
—
(92)
—
(342)
306
51
358
—
—
—
—
—
—
—
—
—
—
—
—
—
— 6,330
— 2,127
— 8,458
— 2,192 1,163
— 2,235
742
— 4,427 1,905
— 3,667
— 3,401
— 7,068
2,256 16,101
1,132 9,844
3,389 25,946
580
—
545
—
—
—
1
—
—
(603)
— (3,636)
— (3,114)
1
—
—
—
(1)
—
—
(362)
—
—
93
(627)
—
(896)
(26)
—
—
28
(367)
—
(364)
—
—
—
—
—
—
—
570
—
—
263
(376)
—
457
(9)
—
—
—
503
546
—
386
(293) (2,358)
— (3,636)
(301) (4,561)
— 1,921
— 3,423
— 5,344
— 1,567 1,382
— 1,964
158
— 3,531 1,541
— 3,883
— 3,641
— 7,524
2,058 11,118
1,029 10,267
3,087 21,385
108
56
164
29
8
—
—
(35)
(3)
(2)
141
21
162
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,130
6
447
6 1,577
508 9,324
— 8,067
508 17,391
2
—
—
—
—
—
2
(86)
—
—
139
(124)
(28)
(99)
285 1,022
—
—
18 1,681
422
—
(470)
(69)
— (1,361)
234 1,294
2
965
513
6
8 1,478
600 11,373
142 7,312
741 18,685
10
—
10
—
—
1
—
(5)
—
(4)
7
—
7
— 11,080
— 8,576
— 19,656
— 1,251
—
8
— 1,701
561
—
(703)
—
— (1,393)
— 1,426
— 13,088
— 7,994
— 21,082
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
493
207
700
108 6,330
56 2,127
164 8,458
— 3,323 1,670 9,324 3,677
6 2,682
742 8,067 3,401
6 6,004 2,413 17,391 7,078
2,256 27,181
1,132 18,421
3,389 45,601
At 31 December
Developed
Undeveloped
306
51
358
141 1,921
21 3,423
162 5,344
2 2,532 1,982 11,373 3,890
300 7,312 3,641
6 2,477
8 5,009 2,282 18,685 7,531
2,058 24,206
1,029 18,260
3,087 42,467
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 1316 billion cubic feet of natural gas associated with Assets Held for Sale in Oman.
d Includes 158 billion cubic feet of natural gas consumed in operations, 103 billion cubic feet in subsidiaries, 55 billion cubic feet in equity-accounted entities.
e Includes 1,059 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 1,640 billion cubic feet of natural gas in respect of the 10.01% non-controlling interest in Rosneft including 614 billion cubic feet held through bp’s interests in Russia other than Rosneft.
h Total proved gas reserves held as part of our equity interest in Rosneft is 16,324 billion cubic feet, comprising 0 billion cubic feet in Venezuela, 7 billion cubic feet in Vietnam, 420 billion cubic feet in
Egypt and 15,897 billion cubic feet in Russia.
bp Annual Report and Form 20-F 2020
241
Movements in estimated net proved reserves – continued
Total hydrocarbonsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place
At 31 Decemberh
Developed
Undeveloped
Equity-accounted entities (bp share)h
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place
At 31 Decemberi j
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
USd
million barrels of oil equivalentc
2020
Africa
Asia
Australasia
Total
Russia
Rest of
Asiad
300
241
540
(110)
—
—
—
(53)
—
(163)
221
157
378
—
—
—
—
—
—
—
—
—
—
—
—
—
— 2,384
— 1,459
— 3,842
40
179
218
60
—
118
—
—
—
3
—
—
(259)
— (1,072)
— (1,150)
22
—
—
—
(8)
—
14
— 1,143
— 1,549
— 2,692
37
195
232
387
411
798
(62)
—
—
21
(111)
—
(152)
280
366
646
369
171
540
(21)
3
—
5
(110)
—
(123)
367
50
417
— 1,707
— 1,111
— 2,818
419 5,604
199 3,771
618 9,375
—
—
—
—
—
—
—
273
—
—
56
(202)
—
127
174
11
122
—
—
—
84
—
(57)
(800)
— (1,072)
(46) (1,492)
— 1,770
— 1,175
— 2,945
391 4,210
182 3,673
573 7,883
139
47
186
1
11
—
—
(25)
(1)
(15)
142
29
171
—
—
—
—
—
—
—
—
—
—
—
—
—
—
21
21
7
—
—
—
—
—
7
5
22
27
488
334
822
100 4,856
— 3,978
100 8,834
(13)
—
1
41
(42)
(40)
(53)
53
—
3
—
(14)
—
42
216
—
949
311
(412)
(910)
153
443
326
769
118 5,192
25 3,796
143 8,988
2
—
2
—
—
—
—
(1)
—
—
1
—
2
— 5,585
— 4,381
— 9,965
—
—
—
—
—
—
—
263
11
954
352
(495)
(951)
134
— 5,902
— 4,198
— 10,100
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
300
241
540
139 2,384
47 1,459
186 3,842
875
40
199
746
239 1,621
469 4,856 1,708
171 3,978 1,112
640 8,834 2,820
419 11,189
199 8,152
618 19,341
At 31 December
Developed
Undeveloped
221
157
378
142 1,143
29 1,549
171 2,692
43
724
692
217
259 1,415
485 5,192 1,771
74 3,796 1,175
560 8,988 2,946
391 10,112
182 7,871
573 17,982
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Includes 264 million barrels of oil equivalent associated with Assets Held for Sale in Oman.
e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
f Includes 27 million barrels of oil equivalent of natural gas consumed in operations, 18 million barrels of oil equivalent in subsidiaries, 10 million barrels of oil equivalent in equity-accounted entities.
g Includes 194 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i Includes 687 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124mmboe held through bp’s interests in Russia other than Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 8,498 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Iraq and Canada, 0 million barrels of
oil equivalent in Venezuela, 1 million barrels of oil equivalent in Vietnam, 73 million barrels of oil equivalent in Egypt and 8,423 million barrels of oil equivalent in Russia.
242
bp Annual Report and Form 20-F 2020
Movements in estimated net proved reserves – continued
Crude oila b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Financial statements
million barrels
2019
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USc d
Rest of
North
America
Russia
Rest of
Asia
223
243
466
(23)
—
—
—
(36)
—
(59)
206
200
406
—
—
—
—
—
—
—
—
—
—
—
—
—
962
—
—
802
— 1,764
43
190
234
—
—
—
—
—
—
—
72
189
—
34
(143)
(12)
141
(8)
1
—
—
(9)
—
(16)
— 1,063
—
842
— 1,905
40
179
218
57
100
157
2
4
—
—
(13)
—
(7)
115
35
150
—
—
—
—
—
—
—
—
—
—
—
—
—
—
19
19
1
—
—
—
—
—
1
—
20
20
43
209
253
40
198
238
8
5
14
1
—
—
—
(3)
—
(2)
7
5
12
293
259
552
(13)
—
—
33
(24)
—
(4)
291
257
548
302
264
566
298
262
560
223
36
259
39
—
—
—
(57)
(45)
(63)
156
40
196
— 1,126
—
482
— 1,608
30 2,615
5 1,763
34 4,378
—
—
—
—
—
—
—
104
—
1
11
(125)
—
(9)
2
—
—
—
(6)
—
(4)
187
191
1
45
(378)
(57)
(12)
— 1,074
—
525
— 1,599
26 2,572
4 1,794
30 4,367
1 3,190
— 2,414
1 5,604
1
—
—
—
—
—
1
158
—
7
277
(345)
(6)
91
2 3,159
— 2,535
2 5,695
—
—
—
—
—
—
—
—
—
—
—
—
—
— 3,541
— 2,792
— 6,333
—
—
—
—
—
—
—
147
4
7
310
(382)
(6)
81
— 3,567
— 2,847
— 6,415
224 3,190 1,126
482
260 5,604 1,608
36 2,414
30 6,156
5 4,555
34 10,711
158 3,159 1,074
525
198 5,695 1,599
40 2,535
26 6,140
4 4,642
30 10,781
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
223
243
466
962
57
100
802
157 1,764
At 31 December
Developed
Undeveloped
206
200
406
115 1,063
842
150 1,905
35
a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying
production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe
Bay Royalty Trust.
d Includes 362 million barrels of crude oil associated with Assets Held for Sale in the USA.
e Includes 4 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 346 million barrels of crude oil in respect of the 6.17% non-controlling interest in Rosneft, including 26 mmbbl held through bp’s interests in Russia other than Rosneft.
h Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,604 million barrels, comprising less than 1 million barrels in Egypt, Vietnam, Iraq and Canada, 35 million barrels in
Venezuela and 5,568 million barrels in Russia.
bp Annual Report and Form 20-F 2020
243
Movements in estimated net proved reserves – continued
Natural gas liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
million barrels
2019
8
6
14
—
1
—
—
(1)
—
(1)
8
5
13
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4
3
7
—
1
—
—
(1)
—
—
5
3
7
4
3
7
5
3
7
266
246
511
(46)
62
—
1
(33)
(17)
(32)
229
250
479
—
—
—
—
—
—
—
—
—
—
—
—
—
266
246
511
229
250
479
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
25
27
(1)
—
—
—
(3)
—
(4)
2
21
23
—
—
—
3
—
—
—
—
—
2
2
—
2
2
25
27
4
21
25
14
4
18
—
—
—
—
(3)
—
(3)
12
4
16
7
—
7
5
—
—
—
(2)
—
4
11
—
11
22
4
26
23
4
27
—
—
—
—
—
—
—
—
—
—
—
—
—
103
51
154
(11)
—
—
—
(2)
—
(13)
89
52
141
103
51
154
89
52
141
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5
—
5
—
—
—
—
(1)
—
(1)
4
—
4
—
—
—
—
—
—
—
—
—
—
—
—
—
5
—
5
4
—
4
295
280
576
(47)
63
—
1
(41)
(17)
(41)
255
280
535
114
54
169
(3)
1
—
—
(4)
—
(7)
107
55
162
409
335
744
363
334
697
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
8
6
14
At 31 December
Developed
Undeveloped
8
5
13
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 94 million barrels of NGL associated with Assets Held for Sale in the USA.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
e Includes 7 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 11 million barrels of NGLs in respect of the 7.90% non-controlling interest in Rosneft.
h Total proved NGL reserves held as part of our equity interest in Rosneft is 141 million barrels, comprising less than 1 million barrels in Egypt, Venezuela, Vietnam and Canada, and 141 million barrels in
Russia.
244
bp Annual Report and Form 20-F 2020
Movements in estimated net proved reserves – continued
Total liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place
At 31 Decemberf
Developed
Undeveloped
Equity-accounted entities (bp share)g
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberh i
Developed
Undeveloped
Financial statements
million barrels
2019
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USc d
Rest of
North
America
Russia
Rest of
Asia
231
249
480
(24)
1
—
—
(38)
—
(60)
214
205
420
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,228
— 1,048
— 2,276
43
190
234
—
—
—
—
—
—
—
26
252
—
35
(176)
(28)
109
(8)
1
—
—
(9)
—
(16)
— 1,292
— 1,092
— 2,384
40
179
218
60
104
164
2
5
—
—
(14)
—
(7)
120
37
157
—
—
—
—
—
—
—
—
—
—
—
—
—
—
19
19
1
—
—
—
—
—
1
—
20
20
44
209
253
40
198
238
10
30
41
—
—
—
—
(6)
—
(6)
9
26
35
293
259
552
(11)
—
—
33
(24)
—
(1)
293
257
550
303
289
593
302
283
585
237
40
277
40
—
—
—
(60)
(45)
(65)
168
43
212
— 1,126
—
482
— 1,608
35 2,910
5 2,044
39 4,954
—
—
—
—
—
—
—
104
—
1
11
(125)
—
(9)
2
—
—
—
(7)
—
(5)
140
254
1
46
(420)
(74)
(52)
— 1,074
—
525
— 1,599
30 2,828
4 2,074
34 4,902
8 3,293
— 2,465
8 5,758
7
—
—
—
(2)
—
5
146
—
7
277
(346)
(6)
78
13 3,248
— 2,588
13 5,836
—
—
—
—
—
—
—
—
—
—
—
—
—
— 3,655
— 2,846
— 6,502
—
—
—
—
—
—
—
145
5
7
310
(386)
(6)
75
— 3,675
— 2,902
— 6,576
245 3,293 1,126
482
285 5,758 1,608
40 2,465
35 6,565
5 4,890
39 11,456
181 3,248 1,074
525
224 5,836 1,599
43 2,588
30 6,502
4 4,976
34 11,478
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
231
249
480
60 1,228
104 1,048
164 2,276
At 31 December
Developed
Undeveloped
214
205
420
120 1,292
37 1,092
157 2,384
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of
the BP Prudhoe Bay Royalty Trust.
d Includes 456 million barrels associated with Assets Held for Sale in the USA.
e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
f Also includes 11 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 357 million barrels in respect of the non-controlling interest in Rosneft, including 26 mmboe held through bp’s interests in Russia other than Rosneft.
i Total proved liquid reserves held as part of our equity interest in Rosneft is 5,745 million barrels, comprising 35 million barrels in Venezuela, less than 1 million barrels in Iraq, Canada, Egypt and Vietnam
and 5,709 million barrels in Russia.
bp Annual Report and Form 20-F 2020
245
Movements in estimated net proved reserves – continued
Natural gasa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
billion cubic feet
2019
439
343
782
(34)
9
—
—
(57)
—
(82)
493
207
700
—
—
—
—
—
—
—
—
—
—
—
—
—
— 6,270
— 5,056
— 11,326
— 2,168 1,313
— 3,073 1,067
— 5,241 2,380
— 3,599
— 3,218
— 6,817
2,630 16,420
1,179 13,936
3,809 30,355
—
—
—
—
—
—
—
(1,877)
307
—
11
(923)
(386)
(2,869)
1
—
—
—
(1)
—
—
(263)
—
—
178
(729)
—
(814)
(4)
—
—
—
(450)
(21)
(475)
—
—
—
—
—
—
—
285
—
50
299
(383)
—
251
(129)
—
—
—
(291)
—
(420)
(2,022)
315
50
488
(2,834)
(406)
(4,410)
— 6,330
— 2,127
— 8,458
— 2,192 1,163
— 2,235
742
— 4,427 1,905
— 3,667
— 3,401
— 7,068
2,256 16,101
1,132 9,844
3,389 25,946
107
55
161
9
15
—
—
(22)
—
2
108
56
164
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,207
4
446
4 1,653
391 7,798
143 8,719
534 16,517
3
—
—
—
—
—
3
(120)
—
—
180
(135)
—
(75)
38
—
—
—
(65)
—
(27)
789
—
—
534
(448)
—
874
— 1,130
447
6
6 1,577
507 9,324
— 8,067
507 17,391
12
4
15
—
—
—
—
(5)
—
(5)
10
—
10
— 9,515
— 9,369
— 18,884
—
—
—
—
—
—
—
718
15
—
714
(676)
—
772
— 11,079
— 8,576
— 19,656
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
439
343
782
107 6,270
55 5,056
161 11,326
— 3,375 1,704 7,798 3,610
4 3,519 1,210 8,719 3,221
4 6,894 2,914 16,517 6,832
2,630 25,934
1,179 23,305
3,809 49,239
At 31 December
Developed
Undeveloped
493
207
700
108 6,330
56 2,127
164 8,458
— 3,323 1,670 9,324 3,677
742 8,067 3,401
6 2,682
6 6,004 2,412 17,391 7,078
2,256 27,181
1,132 18,421
3,389 45,601
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 3,054 billion cubic feet of natural gas associated with Assets Held for Sale in the USA.
d Includes 188 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.
e Includes 1,330 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 1,433 billion cubic feet of natural gas in respect of the 9.72% non-controlling interest in Rosneft including 569 billion cubic feet held through bp’s interests in Russia other than Rosneft.
h Total proved gas reserves held as part of our equity interest in Rosneft is 14,705 billion cubic feet, comprising 28 billion cubic feet in Venezuela, 10 billion cubic feet in Vietnam, 171 billion cubic feet in
Egypt and 14,495 billion cubic feet in Russia.
246
bp Annual Report and Form 20-F 2020
Movements in estimated net proved reserves – continued
Total hydrocarbonsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionf g
Sales of reserves-in-place
At 31 Decemberh
Developed
Undeveloped
Equity-accounted entities (bp share)i
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionf
Sales of reserves-in-place
At 31 Decemberj k
Developed
Undeveloped
Financial statements
million barrels of oil equivalentc
2019
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USd e
Rest of
North
America
Russia
Rest of
Asia
307
308
615
(29)
3
—
—
(48)
—
(74)
300
241
540
—
—
—
—
—
—
—
—
—
—
—
—
—
— 2,309
— 1,919
— 4,228
43
190
234
—
—
—
—
—
—
—
(297)
305
—
36
(335)
(95)
(386)
(8)
1
—
—
(9)
—
(16)
— 2,384
— 1,459
— 3,842
40
179
218
384
560
944
(45)
—
—
31
(131)
—
(146)
387
411
798
464
224
687
39
—
—
—
(137)
(49)
(147)
369
171
540
— 1,746
— 1,037
— 2,783
488 5,741
208 4,447
696 10,188
—
—
—
—
—
—
—
153
—
10
63
(191)
—
35
(21)
—
—
—
(57)
—
(78)
(208)
309
10
130
(908)
(144)
(813)
— 1,707
— 1,111
— 2,818
419 5,604
199 3,771
618 9,375
79
113
192
4
7
—
—
(17)
—
(6)
139
47
186
—
—
—
—
—
—
—
—
—
—
—
—
—
—
20
20
1
—
—
—
—
—
1
—
21
21
501
336
837
76 4,638
25 3,968
101 8,605
(31)
—
—
64
(47)
—
(14)
13
—
—
—
(13)
—
—
282
—
7
369
(424)
(6)
229
488
334
822
100 4,856
— 3,978
100 8,834
2
1
3
—
—
—
—
(1)
—
(1)
2
—
2
— 5,296
— 4,462
— 9,757
—
—
—
—
—
—
—
269
7
7
434
(503)
(6)
208
— 5,585
— 4,381
— 9,965
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
307
308
615
79 2,309
113 1,919
192 4,228
885
44
210
896
253 1,781
539 4,638 1,749
249 3,968 1,037
788 8,605 2,786
488 11,037
208 8,908
696 19,945
At 31 December
Developed
Undeveloped
300
241
540
139 2,384
47 1,459
186 3,842
40
875
746
199
239 1,621
469 4,856 1,708
171 3,978 1,112
640 8,834 2,820
419 11,189
199 8,152
618 19,341
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 4.5 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of
the BP Prudhoe Bay Royalty Trust.
e Includes 982 million barrels of oil equivalent associated with Assets Held for Sale in the USA.
f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
g Includes 32 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities.
h Includes 240 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
j Includes 603 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 124 mmboe held through bp’s interests in Russia other than Rosneft.
k Total proved reserves held as part of our equity interest in Rosneft is 8,281 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Iraq and Canada, 40 million barrels of
oil equivalent in Venezuela, 2 million barrels of oil equivalent in Vietnam, 30 million barrels of oil equivalent in Egypt and 8,208 million barrels of oil equivalent in Russia.
bp Annual Report and Form 20-F 2020
247
Movements in estimated net proved reserves – continued
Crude oila b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberd e
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg
Developed
Undeveloped
Europe
North
America
South
America
UK
Rest of
Europe
USc
Rest of
North
America
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
million barrels
2018
245
164
409
22
—
93
15
(37)
(37)
57
223
243
466
—
—
—
—
—
—
—
—
—
—
—
—
—
932
—
—
492
— 1,423
54
195
248
—
—
—
—
—
—
—
116
51
412
17
(137)
(118)
341
(6)
—
—
—
(9)
—
(15)
962
—
—
802
— 1,764
43
190
234
56
89
145
11
13
—
—
(13)
—
12
57
100
157
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
19
—
—
19
—
19
19
54
195
249
43
209
253
10
6
16
1
—
—
—
(3)
—
(2)
8
5
14
285
263
548
7
—
—
21
(25)
—
4
293
259
552
295
269
564
302
264
566
281
28
309
11
1
—
13
(75)
—
(50)
223
36
259
— 1,040
—
642
— 1,682
31 2,592
11 1,537
42 4,129
—
—
—
—
—
—
—
40
—
—
—
(114)
—
(74)
(2)
—
—
—
(6)
—
(8)
183
52
504
46
(381)
(155)
249
— 1,126
—
482
— 1,608
30 2,615
5 1,763
34 4,378
1 3,124
— 2,251
1 5,374
—
—
—
—
—
—
(1)
150
—
89
326
(335)
—
229
1 3,190
— 2,414
1 5,604
6
—
6
—
—
—
—
(6)
—
(6)
—
—
—
— 3,473
— 2,603
— 6,076
—
—
—
—
—
—
—
168
13
89
366
(379)
—
257
— 3,541
— 2,792
— 6,333
282 3,124 1,047
642
310 5,374 1,688
28 2,251
31 6,064
11 4,140
42 10,205
224 3,190 1,126
482
260 5,604 1,608
36 2,414
30 6,156
5 4,555
34 10,711
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
245
164
409
56
89
932
492
145 1,423
At 31 December
Developed
Undeveloped
223
243
466
57
962
802
100
157 1,764
a Crude oil includes condensate and bitumen. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying
production and the option and ability to make lifting and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe
Bay Royalty Trust.
d Includes 4 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 344 million barrels of crude oil in respect of the 6.28% non-controlling interest in Rosneft, including 24 mmbbl held through bp’s interests in Russia other than Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,539 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 58 million barrels in Venezuela and
5,481 million barrels in Russia.
248
bp Annual Report and Form 20-F 2020
Movements in estimated net proved reserves – continued
Natural gas liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionc
Sales of reserves-in-place
At 31 Decemberd
Developed
Undeveloped
Equity-accounted entities (bp share)e
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberf g
Developed
Undeveloped
Financial statements
million barrels
2018
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
11
3
14
1
—
—
3
(2)
(3)
—
8
6
14
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4
4
8
—
—
—
—
(1)
—
(1)
4
3
7
4
4
8
4
3
7
177
69
246
20
16
253
1
(25)
—
265
266
246
511
—
—
—
—
—
—
—
—
—
—
—
—
—
177
69
246
266
246
511
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
28
30
—
—
—
—
(3)
—
(3)
2
25
27
—
—
—
—
—
—
—
—
—
—
—
—
—
2
28
30
2
25
27
21
—
21
(3)
2
—
3
(3)
—
(2)
14
4
18
10
—
10
(1)
—
—
—
(1)
—
(3)
7
—
7
31
—
31
22
4
26
—
—
—
—
—
—
—
—
—
—
—
—
—
82
49
131
25
—
—
—
(2)
—
23
103
51
154
82
49
131
103
51
154
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5
1
6
—
—
—
—
(1)
—
(1)
5
—
5
—
—
—
—
—
—
—
—
—
—
—
—
—
5
1
6
5
—
5
216
102
318
17
18
253
7
(34)
(3)
258
295
280
576
97
53
149
23
—
—
—
(4)
—
19
114
54
169
313
154
467
409
335
744
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
11
3
14
At 31 December
Developed
Undeveloped
8
6
14
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
d Includes 8 million barrels of NGL in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 12 million barrels of NGLs in respect of the 7.82% non-controlling interest in Rosneft.
g Total proved NGL reserves held as part of our equity interest in Rosneft is 154 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 154 million barrels in Russia.
bp Annual Report and Form 20-F 2020
249
Movements in estimated net proved reserves – continued
Total liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (bp share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg h
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
million barrels
2018
256
167
424
23
—
93
18
(39)
(40)
56
231
249
480
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,108
—
561
— 1,669
54
195
248
—
—
—
—
—
—
—
136
67
665
18
(162)
(118)
606
(6)
—
—
—
(9)
—
(15)
— 1,228
— 1,048
— 2,276
43
190
234
60
93
153
11
13
—
—
(13)
—
11
60
104
164
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
19
—
—
19
—
19
19
54
195
249
44
209
253
12
34
46
1
—
—
—
(6)
—
(5)
10
30
41
285
263
548
7
—
—
21
(25)
—
4
293
259
552
297
297
594
303
289
593
301
28
329
8
3
—
16
(79)
—
(52)
237
40
277
— 1,040
—
642
— 1,682
36 2,808
12 1,639
48 4,447
—
—
—
—
—
—
—
40
—
—
—
(114)
—
(74)
(2)
—
—
—
(7)
—
(9)
200
70
758
52
(415)
(158)
507
— 1,126
—
482
— 1,608
35 2,910
5 2,044
39 4,954
11 3,206
— 2,300
12 5,505
(2)
—
—
—
(2)
—
(3)
175
—
89
326
(337)
—
253
8 3,293
— 2,465
8 5,758
6
—
6
—
—
—
—
(6)
—
(6)
—
—
—
— 3,569
— 2,656
— 6,225
—
—
—
—
—
—
—
191
13
89
366
(383)
—
277
— 3,655
— 2,846
— 6,502
313 3,206 1,047
642
341 5,505 1,688
28 2,300
36 6,377
12 4,295
48 10,672
245 3,293 1,126
482
285 5,758 1,608
40 2,465
35 6,565
5 4,890
39 11,456
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
256
167
424
60 1,108
561
93
153 1,669
At 31 December
Developed
Undeveloped
231
249
480
60 1,228
104 1,048
164 2,276
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of
the BP Prudhoe Bay Royalty Trust.
d Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
e Also includes 12 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 356 million barrels in respect of the non-controlling interest in Rosneft, including 24 mmboe held through bp’s interests in Russia other than Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,693 million barrels, comprising less than 1 million barrels in Canada, 58 million barrels in Venezuela, less than 1 million
barrels in Vietnam and 5,635 million barrels in Russia.
250
bp Annual Report and Form 20-F 2020
Movements in estimated net proved reserves – continued
Natural gasa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionc
Sales of reserves-in-place
At 31 Decemberd
Developed
Undeveloped
Equity-accounted entities (bp share)e
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionc
Sales of reserves-in-place
At 31 Decemberf g
Developed
Undeveloped
Financial statements
billion cubic feet
2018
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
523
320
843
84
—
40
60
(66)
(178)
(61)
439
343
782
—
—
—
—
—
—
—
—
—
—
—
—
—
— 5,238
— 3,086
— 8,323
(1) 2,862 1,159
— 3,330 1,510
(1) 6,193 2,670
— 2,755
— 4,245
— 7,000
2,730 15,266
1,505 13,997
4,235 29,263
—
10
— 1,315
— 2,655
11
—
(751)
—
—
(237)
— 3,003
3
—
—
—
(3)
—
1
(195)
—
—
31
(788)
—
(951)
(444)
—
—
578
(423)
—
(290)
—
—
—
—
—
—
—
140
—
—
—
(324)
—
(184)
(123)
(524)
— 1,315
— 2,695
680
—
(2,658)
(303)
(416)
—
(426) 1,092
— 6,270
— 5,056
— 11,326
— 2,168 1,313
— 3,073 1,067
— 5,241 2,380
— 3,599
— 3,218
— 6,817
2,630 16,420
1,179 13,936
3,809 30,355
112
69
180
2
—
—
—
(22)
—
(19)
107
55
161
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,274
—
450
— 1,724
476 6,077
146 7,173
622 13,250
—
—
—
4
—
—
3
(50)
1
—
122
(145)
—
(71)
805
(39)
—
—
— 2,413
512
—
(464)
(48)
—
—
(87) 3,267
— 1,207
446
4
4 1,653
391 7,798
143 8,719
534 16,517
17
3
20
2
—
—
—
(6)
—
(5)
12
4
15
— 7,955
— 7,841
— 15,796
719
—
—
1
— 2,413
638
—
(685)
—
—
—
— 3,087
— 9,515
— 9,369
— 18,884
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
523
320
843
112 5,238
69 3,086
180 8,323
— 4,136 1,635 6,077 2,771
— 3,781 1,656 7,173 4,249
— 7,917 3,291 13,250 7,020
2,730 23,221
1,505 21,838
4,235 45,060
At 31 December
Developed
Undeveloped
439
343
782
107 6,270
55 5,056
161 11,326
— 3,375 1,704 7,798 3,610
4 3,519 1,210 8,719 3,221
4 6,894 2,914 16,517 6,832
2,630 25,934
1,179 23,305
3,809 49,239
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 181 billion cubic feet of natural gas consumed in operations, 139 billion cubic feet in subsidiaries, 42 billion cubic feet in equity-accounted entities.
d Includes 1,573 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 1,211 billion cubic feet of natural gas in respect of the 8.60% non-controlling interest in Rosneft including 480 billion cubic feet held through bp’s interests in Russia other than Rosneft.
g Total proved gas reserves held as part of our equity interest in Rosneft is 14,325 billion cubic feet, comprising 0 billion cubic feet in Canada, 26 billion cubic feet in Venezuela, 15 billion cubic feet in
Vietnam, 200 billion cubic feet in Egypt and 14,084 billion cubic feet in Russia.
bp Annual Report and Form 20-F 2020
251
Movements in estimated net proved reserves – continued
Total hydrocarbonsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place
At 31 Decemberg
Developed
Undeveloped
Equity-accounted entities (bp share)h
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place
At 31 Decemberi j
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
USd
Rest of
North
America
Russia
Rest of
Asia
million barrels of oil equivalentc
2018
347
222
569
38
—
100
29
(50)
(70)
46
307
308
615
—
—
—
—
—
—
—
—
—
—
—
—
—
— 2,011
— 1,093
— 3,104
505
54
195
608
248 1,114
138
—
—
294
— 1,123
—
20
(292)
—
—
(159)
— 1,124
(5)
—
—
—
(9)
—
(15)
— 2,309
— 1,919
— 4,228
43
190
234
(33)
—
—
5
(142)
—
(169)
384
560
944
501
288
790
(69)
3
—
116
(152)
—
(102)
464
224
687
— 1,515
— 1,374
— 2,889
507 5,440
272 4,052
779 9,492
—
—
—
—
—
—
—
64
—
—
—
(170)
—
(106)
110
(23)
—
297
— 1,222
—
169
(874)
(59)
(229)
—
696
(82)
— 1,746
— 1,037
— 2,783
488 5,741
208 4,447
696 10,188
80
105
184
11
13
—
—
(17)
—
8
79
113
192
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
20
—
—
19
—
20
20
505
341
846
93 4,254
25 3,536
119 7,790
(1)
—
—
42
(50)
—
(9)
(8)
—
—
—
(10)
—
(18)
313
—
505
414
(417)
—
816
501
336
837
76 4,638
25 3,968
101 8,605
9
1
10
—
—
—
—
(7)
—
(7)
2
1
3
— 4,941
— 4,008
— 8,949
—
—
—
—
—
—
—
315
14
505
476
(501)
—
809
— 5,296
— 4,462
— 9,757
Total subsidiaries and equity-accounted entities (bp share)
At 1 January
Developed
Undeveloped
347
222
569
80 2,011
105 1,093
184 3,104
54 1,010
195
949
249 1,959
595 4,254 1,524
314 3,536 1,374
908 7,790 2,899
507 10,381
272 8,060
779 18,441
At 31 December
Developed
Undeveloped
307
308
615
79 2,309
113 1,919
192 4,228
44
885
896
210
253 1,781
539 4,638 1,749
249 3,968 1,037
788 8,605 2,786
488 11,037
208 8,908
696 19,945
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 16 million barrels of oil equivalent upon which a net profits royalty will be payable, over the life of the field under the terms of
the BP Prudhoe Bay Royalty Trust.
e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 24 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities.
g Includes 283 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i Includes 565 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 107 mmboe held through bp’s interests in Russia other than Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 8,163 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 62 million barrels of oil
equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 35 million barrels of oil equivalent in Egypt and 8,063 million barrels of oil equivalent in Russia.
252
bp Annual Report and Form 20-F 2020
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas
reserves
The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural gas
production from the group’s estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures requirements.
Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future
production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates from
the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical information
becomes available and economic conditions change. bp cautions against relying on the information presented because of the highly arbitrary nature of
the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.
Financial statements
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2020
Total
13,900
10,000
800
1,200
1,900
500
— 64,400 4,100 6,700 12,600
— 28,200 3,400 3,600 4,200
— 12,700 1,200 1,700 1,100
500 1,800
—
—
1,100
900 5,500
(500)
— 22,400
200 1,100
(200)
9,200
—
— 93,500 15,900 211,100
5,400 100,100
— 45,300
1,900 32,700
— 13,300
2,600 33,300
— 26,100
6,000 45,000
— 8,800
2,500 15,300
— 2,000
1,400
— 13,200
(300)
700 4,400
— 6,800
3,500 29,700
— 6,300
— 3,100
—
500
— 2,200
500
—
100
—
—
—
—
—
—
—
— 25,100
— 13,000
— 3,300
— 1,700
— 7,100
— 4,400
— 214,800
— 145,700
— 20,800
— 8,000
— 40,300
— 23,500
—
—
—
—
—
—
— 246,200
— 161,800
— 24,600
— 11,900
— 47,900
— 28,000
—
400
—
— 2,700
— 16,800
—
— 19,900
At 31 December
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted future
net cash flowse f
Equity-accounted entities (bp share)g
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted future
net cash flowsh i
Total subsidiaries and equity-accounted entities
Standardized measure of discounted future
net cash flowsj
1,400
400 13,200
(300) 3,400 4,400 16,800 6,800
3,500 49,600
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million
Subsidiaries
Equity-accounted
entities (bp share)
Total subsidiaries and
equity-accounted
entities
(27,200)
12,800
2,500
(70,800)
7,300
27,500
(2,600)
(6,200)
9,700
(47,000)
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeark
a The marker prices used were Brent $41.31/bbl, Henry Hub $1.94/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
(6,000)
4,100
1,400
(19,200)
400
4,600
(2,700)
—
3,400
(14,000)
(21,200)
8,700
1,100
(51,600)
6,900
22,900
100
(6,200)
6,300
(33,000)
decommissioning costs are included.
c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa.
This can result in the standardized measure of discounted future net cash flows being negative.
f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $200 million.
g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
h Non-controlling interests in Rosneft amounted to $1,600 million in Russia.
i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
j Includes future net cash flows for assets held for sale at 31 December 2020.
k Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US
dollars are included within ‘Net changes in prices and production cost’.
bp Annual Report and Form 20-F 2020
253
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas
reserves – continued
Europe
North
America
South
America
UK
Rest of
Europe
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2019
Total
Russia
Rest of
Asia
28,600
13,700
1,700
5,200
8,000
2,700
— 135,900 7,400 11,500 21,200
— 59,200 3,400 5,700 6,700
— 16,400 1,200 2,000 1,300
— 8,700
200 1,300 3,300
— 51,600 2,600 2,500 9,900
600 2,300
— 23,100 1,400
— 135,800 24,000 364,400
6,100 148,000
— 53,200
2,700 42,000
— 16,700
5,300 70,000
— 46,000
9,900 104,400
— 19,900
4,400 41,700
— 7,200
5,300
— 28,500 1,200 1,900 7,600
— 12,700
5,500 62,700
— 10,300
— 3,500
700
—
— 4,700
— 1,400
400
—
—
—
—
—
—
—
— 36,800
— 14,900
— 3,900
— 4,100
— 13,900
— 8,200
— 322,000
— 222,600
— 21,800
— 13,300
— 64,300
— 37,100
—
—
—
—
—
—
— 369,100
— 241,000
— 26,400
— 22,100
— 79,600
— 45,700
— 1,000
—
— 5,700
— 27,200
—
— 33,900
At 31 December
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted future
net cash flowse f
Equity-accounted entities (bp share)g
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted future
net cash flowsh i
Total subsidiaries and equity-accounted entities
Standardized measure of discounted future
net cash flowsj
5,300 1,000 28,500 1,200 7,600 7,600 27,200 12,700
5,500 96,600
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million
Total subsidiaries and
equity-accounted
entities
(35,800)
13,300
6,400
(36,300)
1,400
19,000
(5,800)
(1,400)
12,400
(26,800)
Subsidiaries
Equity-accounted
entities (bp share)
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeark
a The marker prices used were Brent $62.74/bbl, Henry Hub $2.58/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
(27,400)
9,200
3,800
(28,100)
300
16,600
(1,500)
(1,400)
8,300
(20,200)
(8,400)
4,100
2,600
(8,200)
1,100
2,400
(4,300)
—
4,100
(6,600)
decommissioning costs are included.
c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa.
This can result in the standardized measure of discounted future net cash flows being negative.
f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $600 million.
g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
h Non-controlling interests in Rosneft amounted to $2,100 million in Russia.
i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Includes future net cash flows for assets held for sale at 31 December 2019.
k Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US
dollars are included within ‘Net changes in prices and production cost’.
254
bp Annual Report and Form 20-F 2020
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas
reserves – continued
Financial statements
Europe
North
America
South
America
UK
Rest of
Europe
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2018
Total
Russia
Rest of
Asia
At 31 December
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted future net
cash flowse f
Equity-accounted entities (bp share)g
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted future net
cash flowsh i
39,700
15,000
2,100
8,900
13,700
5,000
— 160,000 4,100 17,500 30,400
— 57,600 3,400 7,200 8,500
— 17,800 1,100 2,800 2,600
— 16,600
— 3,200 5,300
(400) 4,300 14,000
— 68,000
700 3,300
(200)
— 29,900
— 147,500 30,000 429,200
7,600 155,100
— 55,800
2,500 45,300
— 16,400
— 51,100
6,900 92,000
— 24,200 13,000 136,800
5,800 53,900
— 9,400
8,700
— 38,100
(200) 3,600 10,700
— 14,800
7,200 82,900
— 12,800
— 4,200
800
—
— 5,900
— 1,900
600
—
—
—
—
—
—
—
— 38,500
— 16,100
— 3,600
— 4,400
— 14,400
— 8,500
— 356,800
— 238,400
— 19,300
— 17,700
— 81,400
— 48,100
—
—
—
—
—
—
— 408,100
— 258,700
— 23,700
— 28,000
— 97,700
— 57,200
— 1,300
—
— 5,900
— 33,300
—
— 40,500
Total subsidiaries and equity-accounted entities
Standardized measure of discounted future net
cash flows
8,700 1,300 38,100
(200) 9,500 10,700 33,300 14,800
7,200 123,400
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
$ million
Total subsidiaries and
equity-accounted
entities
(26,800)
12,800
9,100
54,100
(100)
(21,600)
(2,500)
8,000
8,300
41,300
Subsidiaries
Equity-accounted
entities (bp share)
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yearj
a The marker prices used were Brent $71.43/bbl, Henry Hub $3.10/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included. 2018 comparative for Russia equity-accounted entity future production cost has been restated from $232,100 million to maintain consistency with 2019
presentation.
(18,800)
8,500
5,800
41,000
(2,100)
(17,000)
1,000
7,600
5,200
(8,000)
4,300
3,300
13,100
2,000
(4,600)
(3,500)
400
3,100
10,100
31,200
c Taxation is computed with reference to appropriate year-end statutory corporate income tax rates. 2018 comparative for Russia equity-accounted entity future taxation has been restated from $24,000
million to maintain consistency with 2019 presentation.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and vice versa.
This can result in the standardized measure of discounted future net cash flows being negative.
f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $1,100 million.
g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
h Non-controlling interests in Rosneft amounted to $2,500 million in Russia.
i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
j Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes to US
dollars are included within ‘Net changes in prices and production cost’.
bp Annual Report and Form 20-F 2020
255
Operational and statistical information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include amounts
attributable to assets held for sale.
Crude oil and natural gas production
The following table shows crude oil, natural gas liquids and natural gas production for the years ended 31 December 2020, 2019 and 2018.
Production for the yeara b
Subsidiariesd
Crude oile
2020
2019
2018
Natural gas liquids
2020
2019
2018
Natural gasf
2020
2019
2018
Equity-accounted entities (bp share)
Crude oile
2020
2019
2018
Natural gas liquids
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Africa
Asia
Australasia
Total
Russiac
Rest of
Asia
96
100
101
5
3
5
221
129
152
—
—
—
—
—
—
—
—
—
—
—
—
50
35
34
345
400
385
79
81
60
22
24
24
—
—
—
7
7
7
7
9
9
123
156
204
8
8
11
1,561
2,358
1,900
2
2
7
1,695
1,977
2,136
923
1,138
1,061
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
54
56
55
1
1
1
903
955
933
thousand barrels per day
983
1,046
1,051
15
17
17
thousand barrels per day
101
104
88
2
2
2
375
343
313
—
—
—
million cubic feet per day
6,163
7,366
6,900
795
786
819
966
976
826
thousand barrels per day
1,009
1,047
1,040
—
—
—
—
—
16
—
—
—
2020
2019
2018
Natural gasf
2020
2019
2018
a Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
million cubic feet per day
1,765
1,736
1,760
1,327
1,279
1,286
286
314
335
92
87
80
61
56
59
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
1
—
—
—
—
—
—
—
7
8
6
3
3
4
3
2
2
thousand barrels per day
14
14
12
—
—
—
sales arrangements independently.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Amounts reported for Russia include bp’s share of Rosneft worldwide activities, including insignificant amounts outside Russia.
d All of the oil and liquid production from Canada is bitumen.
e Crude oil includes condensate.
f Natural gas production excludes gas consumed in operations.
256
bp Annual Report and Form 20-F 2020
Operational and statistical information – continued
Productive oil and gas wells and acreage
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and
natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2020. A ‘gross’ well or acre is one in which a
whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fractional working interests in gross
wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field,
on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been
drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves.
Financial statements
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Africa
Asia
Australasia
Totalb
Russiaa
Rest of
Asia
Number of productive wells at 31 December 2020
Oil wellsc
Gas wellsd
– gross
– net
– gross
– net
125
73
39
8
90
27
2
1
1,326
741
6,405
3,898
175
47
238
118
5,551
2,557
1,118
403
291 68,286
62 13,594
455
93
241
102
Oil and natural gas acreage at 31 December 2020
86
Developed
50
1,892
1,010
– gross
– net
– gross
– net
Undevelopede
64
19
140
42
144
63
8,210
1,364
3,645
2,200
1,459
365
4,590 14,948 23,683 34,246 442,967
8,358 19,817 85,477
3,518
850
303
7,887
2,020
475
138
70
1,281
285
9,662
2,520
12 77,876
2 17,578
8,714
4,709
78
16
thousands of acres
181 15,824
4,788
7,571 539,699
3,299 131,928
44
a Based on information received from Rosneft as at 31 December 2020.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes approximately 6,978 gross (1,343 net) multiple completion wells (more than one formation producing into the same well bore).
d Includes approximately 430 gross (203 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.
e Undeveloped acreage includes leases and concessions.
Net oil and gas wells completed or abandoned
The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the
years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling
or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be
incapable of producing hydrocarbons in sufficient quantities to justify completion.
2020
Exploratory
Productive
Dry
Development
Productive
Dry
2019
Exploratory
Productive
Dry
Development
Productive
Dry
2018
Exploratory
Productive
Dry
Development
Productive
Dry
Europe
North
America
South
America
UK
Rest of
Europe
Rest of
North
America
US
Africa
Asia
Australasia
Totala
Russia
Rest of
Asia
—
—
5.3
—
—
1.0
1.7
—
0.3
—
1.4
—
—
—
1.1
1.8
3.1
—
114.6
3.0
0.8
—
0.4
—
—
—
0.6
—
14.3
—
0.4
0.2
—
—
17.2
2.0
61.7
1.0
4.4
—
199.1
—
40.3
0.6
2.0
—
430.9
4.6
0.2
0.3
0.8
1.6
0.8
0.5
3.5
1.1
2.3
0.3
11.6
0.5
5.2
0.4
—
0.2
24.4
5.9
2.4
0.3
193.0
10.0
0.2
—
110.7
0.6
6.0
—
230.8
—
49.6
1.0
0.4
—
594.8
11.9
—
—
1.7
—
—
0.5
2.0
2.0
—
2.4
15.0
—
5.0
—
—
—
24.0
4.9
0.6
—
142.7
6.8
5.0
—
103.9
3.6
14.4
—
137.3
—
53.5
2.6
1.3
—
460.1
13.0
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
bp Annual Report and Form 20-F 2020
257
Operational and statistical information – continued
Drilling and production activities in progress
The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its
equity-accounted entities as of 31 December 2020. Suspended development wells and long-term suspended exploratory wells are also included in the
table.
At 31 December 2020
Exploratory
Gross
Net
Development
Gross
Net
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Africa
Asia
Australasia
Totala
Russia
Rest of
Asia
—
—
2.0
0.7
—
—
5.0
3.1
0.7
0.2
166.0
104.8
1.0
0.4
6.0
3.0
2.0
0.1
7.0
3.2
—
—
4.0
0.8
1.0
0.4
20.0
8.0
13.0
4.7
19.0
4.8
—
—
198.0
25.0
2.0
0.8
406.7
144.0
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
258
bp Annual Report and Form 20-F 2020
Parent company financial statements of BP p.l.c.
Company balance sheet
At 31 December
Non-current assets
Investments
Receivables
Defined benefit pension plan surpluses
Current assets
Receivables
Cash and cash equivalents
Total assets
Current liabilities
Payables
Non-current liabilities
Payables
Deferred tax liabilities
Defined benefit pension plan deficits
Total liabilities
Net assets
Capital and reservesa
Profit and loss account
Brought forward
Profit (loss) for the year
Other movements
Called-up share capital
Share premium account
Other capital and reserves
Financial statements
Note
2020
2
3
4
3
160,544
3,174
7,567
171,285
291
1
292
171,577
$ million
2019
166,256
2,771
6,588
175,615
135
—
135
175,750
5
28,011
18,007
5
6
4
28,084
2,631
236
30,951
58,962
112,615
31,927
2,293
202
34,422
52,429
123,321
92,071
(4,831)
(7,519)
79,721
5,383
12,584
14,927
112,615
96,430
4,470
(8,829)
92,071
5,404
12,417
13,429
123,321
7
a See Statement of changes in equity on page 260 for further information.
The financial statements on pages 259-300 were approved and signed by the chief executive officer on 22 March 2021 having been duly authorized to
do so by the board of directors:
Bernard Looney Chief executive officer
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
259
Company statement of changes in equitya
At 1 January 2020
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividends
Repurchases of ordinary share capital
Share-based payments, net of tax
At 31 December 2020
At 1 January 2019
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividends
Repurchases of ordinary share capital
Share-based payments, net of tax
At 31 December 2019
a See Note 8 for further information.
Share capital
5,404
—
—
—
—
(30)
9
5,383
5,402
—
—
—
52
(59)
9
5,404
Share
premium
account
12,417
—
—
—
—
—
167
12,584
Capital
redemption
reserve
1,498
—
—
—
—
30
—
1,528
12,305
—
—
—
(52)
—
164
12,417
1,439
—
—
—
—
59
—
1,498
Merger
reserve
26,509
—
—
—
—
—
—
26,509
26,509
—
—
—
—
—
—
26,509
Treasury
shares
(14,412)
—
—
—
—
—
1,188
(13,224)
(15,767)
—
—
—
—
—
1,355
(14,412)
$ million
Profit and
loss account
Total equity
92,071 123,321
(4,831)
(4,831)
528
248
(4,303)
(4,583)
(6,367)
(6,367)
(776)
(776)
740
(624)
79,721 112,615
96,430 125,952
4,470
601
5,071
(6,929)
(1,511)
738
92,071 123,321
4,470
401
4,871
(6,929)
(1,511)
(790)
Foreign
currency
translation
reserve
(166)
—
280
280
—
—
—
114
(366)
—
200
200
—
—
—
(166)
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
260
bp Annual Report and Form 20-F 2020
Financial statements
Notes on financial statements
1. Significant accounting policies, judgements, estimates and assumptions
Authorization of financial statements and statement of compliance with Financial Reporting Standard 101 ‘Reduced Disclosure
Framework’ (FRS 101)
The financial statements of BP p.l.c. for the year ended 31 December 2020 were approved and signed by the chief executive officer on 22 March 2021
having been duly authorized to do so by the board of directors. The company meets the definition of a qualifying entity under Financial Reporting
Standard 100 ‘Application of Financial Reporting Requirements’ (FRS 100) issued by the Financial Reporting Council. Accordingly, these financial
statements have been prepared in accordance with FRS 101 and in accordance with the provisions of the UK Companies Act 2006.
Basis of preparation
The financial statements have been prepared on a going concern basis and in accordance with the Companies Act 2006 and applicable UK accounting
standards.
The financial statements have been prepared under the historical cost convention. Historical cost is generally based on the fair value of the
consideration given in exchange for the assets.
As permitted by FRS 101, the company has taken advantage of the disclosure exemptions available in relation to:
(a)
the requirements of IFRS 7 ‘Financial Instruments: Disclosures’;
(b)
(c)
the requirements of paragraphs 10(d), 10(f), 16, 38A, 38B, 38C, 38D, 40A, 40B, 40C, 40D, 111 and 134 to 136 of IAS 1 ‘Presentation of Financial
Statements’;
the requirements in paragraph 38 of IAS 1 'Presentation of Financial Statements' to present comparative information in respect of paragraph
79(a)(iv) of IAS 1.
(d)
the requirements of IAS 7 ‘Statement of Cash Flows’;
(e)
the requirements of paragraphs 30 and 31 of IAS 8 ‘Accounting Policies, Changes in Accounting Estimates and Errors’ in relation to standards not
yet effective;
(f)
the requirements of paragraphs 17 and 18A of IAS 24 ‘Related Party Disclosures’;
(g)
the requirements of IAS 24 ‘Related Party Disclosures’ to disclose related party transactions entered into between two or more members of a
group, provided that any subsidiary which is a party to the transaction is wholly owned by such a member;
(h) the requirements of paragraphs 130(f)(ii), 130(f)(iii), 134(d) to 134(f) and 135(c)-135(e) of IAS 36, Impairment of Assets; and
(i)
the requirement of the second sentence of paragraph 110 and paragraphs 113(a), 114,115, 118, 119(a) to (c), 120 to 127 and 129 of IFRS 15
'Revenue from Contracts with Customers'.
Where required, equivalent disclosures are given in the consolidated financial statements of BP p.l.c.
As permitted by Section 408 of the Companies Act 2006, the income statement of the company is not presented as part of these financial statements.
The financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise
indicated.
Comparative employee cost information in note 13 has been restated due the correction of an accounting error. There is no impact on the company
balance sheet or the statement of changes in equity as a result of this error.
Significant accounting policies: use of judgements, estimates and assumptions
Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for management to make
judgements, estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and
the reported amounts of revenues and expenses. Actual outcomes could differ from the estimates and assumptions used. The accounting judgements
and estimates that have a significant impact on the results of the company are set out in boxed text below, and should be read in conjunction with the
information provided in the Notes to the financial statements.
The areas requiring the most significant judgement and estimation in the preparation of the financial statements are the recoverability of investment
carrying values and pensions. Judgements and estimates, not all of which are significant, made in assessing the impact of the COVID-19 pandemic,
and climate change and the transition to a lower carbon economy on the financial statements are also set out in boxed text below. Where an estimate
has a significant risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next financial year this is specifically
noted within the boxed text.
Judgements and estimates made in assessing the impact of climate change and the transition to a lower carbon economy
Climate change and the transition to a lower carbon economy were considered in preparing the financial statements. These may have significant
impacts on the currently reported amounts of the company’s assets and liabilities discussed below.
Impairment of investments
The energy transition is likely to impact the future prices of commodities such as oil and natural gas which in turn may affect the recoverable amount
of property, plant and equipment, and goodwill in the oil and gas industry. Management’s best estimate oil and natural gas price assumptions for
value-in-use impairment testing were revised downwards during 2020 and the period covered extended to 2050. The revised assumptions sit within
the range of external forecasts considered by management and are broadly in line with a range of transition paths consistent with the goals of the
Paris climate change agreement. Impairments were recognized during 2020 on certain investments where the subsidiary company holds Upstream oil
and gas properties, as a result of the lower price assumptions. See note 2 for further information.
The energy transition may also affect the future development or viability of exploration prospects. The lower price assumptions and work to develop
bp’s new strategy resulted in a review of the recoverability of exploration and intangible assets during 2020. Certain intangible assets were
subsequently written-off, which has resulted in the company recognizing impairments against investments in subsidiary companies holding these
assets.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
261
1. Significant accounting policies, judgements, estimates and assumptions – continued
Judgements and estimates made in assessing the impact of the COVID-19 pandemic and the economic environment
In preparing the financial statements, the following areas involving judgement and estimates were identified as most relevant with regards to the
impact of the COVID-19 pandemic and current economic environment.
Going concern
Liquidity and financing is managed within bp under pooled group-wide arrangements which include the company. As part of assuring the going
concern basis of preparation for the company, the ability and intent of the bp group to support the company has been taken into consideration. The
most recent bp group financial statements (see pages 129 to 230) continue to be prepared on a going concern basis. Forecast liquidity has been
assessed at a group level under a number of scenarios and a reverse stress test performed to support the group’s going concern assertion. In
addition, group management of bp have confirmed that the existing intra-group funding and liquidity arrangements as currently constituted are
expected to continue for the foreseeable future, being no less than twelve months from the approval of these financial statements. No material
uncertainties over going concern or significant judgements or estimates in the assessment were identified. Accordingly, the company will be able to
draw on support from the bp group for the foreseeable future and these financial statements have therefore been prepared on the going concern
basis.
Pensions
The volatility in the financial markets during 2020 impacted the assumptions used for determining the fair value of plan assets and the present value
of defined benefit obligations in the company’s defined benefit pension plans. See significant estimate: pensions and Note 4 for further information.
Investments
Investments in subsidiaries are recorded at cost. The company assesses investments for impairment whenever events or changes in circumstances
indicate that the carrying amount may not be recoverable. If any such indication of impairment exists, the company makes an estimate of its
recoverable amount. Where the carrying amount of an investment exceeds its recoverable amount, the investment is considered impaired and is
written down to its recoverable amount. Where these circumstances have reversed, the impairment previously made is reversed to the extent of the
original cost of the investment.
Significant judgements and estimates: recoverability of asset carrying values
Determination as to whether, and by how much, an asset, CGU, or investment holding company chain (defined as each direct subsidiary and its own
investments), is impaired involves management estimates on highly uncertain matters such as the effects of inflation and deflation on operating
expenses, discount rates, capital expenditure, production profiles, reserves and resources, and future commodity prices, including the outlook for
global or regional market supply-and-demand conditions for crude oil, natural gas and refined products. Alternative groupings of assets or CGUs may
result in a different outcome from impairment testing.
The recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. Fair value less costs of disposal may be
determined based on expected sales proceeds or similar recent market transaction data. Details of impairment charges recognized in the profit and
loss account and the carrying amounts of investments are shown in Note 2. The estimates for assumptions made in impairment tests in 2020 relating
to discount rates and oil and gas properties are discussed below. Changes in the economic environment or other facts and circumstances may
necessitate revisions to these assumptions and could result in a material change to the carrying values of the group's assets within the next financial
year.
Discount rates
For discounted cash flow calculations, future cash flows are adjusted for risks specific to the CGU. Value-in-use calculations are typically discounted
using a pre-tax discount rate based upon the cost of funding the group derived from an established model, adjusted to a pre-tax basis and
incorporating a market participant capital structure and country risk premiums. Fair value less costs of disposal discounted cash flow calculations use
the post-tax discount rate. The discount rates applied in impairment tests are reassessed each year and in 2020, the pre-tax discount rate typically
ranged from 7% to 15% (2019 7% to 13%) depending on the risk premium and applicable tax rate in the geographic location of the CGU.
Oil and natural gas properties
For Upstream oil and natural gas properties in subsidiaries, expected future cash flows are estimated using management’s best estimate of future oil
and natural gas prices, and production and reserves volumes. The estimated future level of production in all impairment tests is based on assumptions
about future commodity prices, production and development costs, field decline rates, current fiscal regimes and other factors. A change in the
discount rate, reserves, resources or the oil and gas price assumptions in the next financial year may result in a recoverable amount of one or more of
these assets above or below the current carrying amount and therefore there is a risk of impairment reversals or charges in that period. Management
consider that reasonably possible changes in the discount rate or forecast revenue, arising from a change in oil and natural gas prices and/or
production could result in a material change in their carrying amounts within the next financial year.
Oil and natural gas prices
The price assumptions used for value in use impairment testing are based on those used for investment appraisal. The investment appraisal price
assumptions are recommended by the senior vice president economic & energy insights after considering a range of external prices, and supply and
demand forecasts under various energy transition scenarios. They are reviewed and approved by management. As a result of the current uncertainty
over the pace of transition to lower-carbon supply and demand and the social, political and environmental actions that will be taken to meet the goals
of the Paris climate change agreement, the forecasts and scenarios considered include those where those goals are met as well as those where they
are not met.
bp sees the prospect of an enduring impact on the global economy as a result of the COVID-19 pandemic, with the potential for weaker demand for
energy for a sustained period. bp’s management also expects that the aftermath of the pandemic will accelerate the pace of transition to a lower
carbon economy and energy system as countries seek to ‘build back better’ so that their economies will be more resilient in the future. As a result of
all the above, bp revised its price assumptions for value-in-use impairment testing, lowering them compared to those used in 2019 and extending the
period covered to 2050. A summary of the group’s revised price assumptions, in real 2020 terms, is provided below. The assumptions represent
management’s best estimate of future prices, which sit within the range of external forecasts considered as appropriate for the purpose. They are
considered by bp to be broadly in line with a range of transition paths consistent with the Paris climate goals. However, they do not correspond to any
specific Paris-consistent scenario. An inflation rate of 2% (2019 2%) is applied to determine the price assumptions in nominal terms.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
262
bp Annual Report and Form 20-F 2020
Financial statements
1. Significant accounting policies, judgements, estimates and assumptions – continued
Brent oil ($/bbl)
Henry Hub gas ($/mmBtu)
2021
50
3.00
2025
50
3.00
2030
60
3.00
2040
60
3.00
2050
50
2.75
Impairment charges were recognized in 2020 following the downward revision of the price assumptions. See Note 2 for further information. The
majority of reserves and resources that support the carrying value of the company’s subsidiaries holding oil and gas properties are expected to be
produced over the next 10 years.
Oil and natural gas reserves
In addition to oil and natural gas prices, significant technical and commercial assessments are required to estimate oil and natural gas reserves held by
the company’s subsidiaries. Reserves estimates are regularly reviewed and updated. Factors such as the availability of geological and engineering
data, reservoir performance data, acquisition and divestment activity and drilling of new wells all impact on the determination of estimates of oil and
natural gas reserves. bp bases its reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments
based on conventional industry practice and regulatory requirements.
Reserves assumptions used for value-in-use tests in the company’s subsidiaries reflect the reserves and resources that management currently intend
to develop. The recoverable amount of oil and gas properties is determined using a combination of inputs including reserves, resources and
production volumes. Risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved or probable.
Foreign currency translation
The functional and presentation currency of the financial statements is US dollars. Transactions in foreign currencies are initially recorded in the
functional currency by applying the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies
are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences are included in the
income statement. Non-monetary assets and liabilities, other than those measured at fair value, are not retranslated subsequent to initial recognition.
Exchange adjustments arising when the opening net assets and the profits for the year retained by a non-US dollar functional currency branch are
translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Income statement
transactions are translated into US dollars using the average exchange rate for the reporting period.
Financial guarantees
The company enters into financial guarantee contracts with its subsidiaries. At the inception of a financial guarantee contract, a liability is recognized
initially at fair value and then subsequently measured at the higher of the contract’s estimated expected credit loss and the amount initially recognized
less, where appropriate, cumulative amortization.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees of the company and other members of the group is measured by reference to the fair value of
the equity instruments on the date on which they are granted and is recognized as an expense over the vesting period, which ends on the date on
which the employees become fully entitled to the award. A corresponding credit is recognized within equity. Fair value is determined by using an
appropriate, widely used, valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other than conditions
linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees contribute to a
savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within the control of
the employee, is treated as a cancellation and any remaining unrecognized cost is expensed.
For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are measured at
the fair value of the goods or services received, unless their fair value cannot be reliably estimated. If the fair value of the goods and services received
cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted.
Cash-settled transactions
The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding
liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in
fair value recognized in the income statement.
Pensions
The defined benefit pension plans are plans that share risks between entities under common control. In each instance BP p.l.c. is the principal employer
and carries the whole plan surplus or deficit on its balance sheet. The cost of providing benefits under the company’s defined benefit plans is
determined separately for each plan using the projected unit credit method, which attributes entitlement to benefits to the current period to determine
current service cost and to the current and prior periods to determine the present value of the defined benefit obligation. Past service costs, resulting
from either a plan amendment or a curtailment (a reduction in future obligations as a result of a material reduction in the plan membership), are
recognized immediately when the company becomes committed to a change.
Net interest expense relating to pensions, which is recognized in the income statement, represents the net change in present value of plan obligations
and the value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit
obligation at the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or
plan assets during the year.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
263
1. Significant accounting policies, judgements, estimates and assumptions – continued
Remeasurements of the defined benefit liability and asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts
included in net interest described above) are recognized within other comprehensive income in the period in which they occur and are not subsequently
reclassified to profit and loss.
The defined benefit pension plan surplus or deficit recognized on the balance sheet for each plan comprises the difference between the present value
of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and the fair value of plan assets out of which the
obligations are to be settled directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price.
Defined benefit pension plan surpluses are only recognized to the extent they are recoverable, typically by way of refund.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate: pensions
Accounting for defined benefit pensions involves making significant estimates when measuring the company's pension plan surpluses and deficits.
These estimates require assumptions to be made about many uncertainties.
Pension assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit
obligation at the year end and hence the surpluses and deficits recorded on the company’s balance sheet, and pension expense for the following year.
The assumptions used are provided in Note 4.
The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels.
Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with resultant
effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation rate, could result in
material changes to the carrying amounts of the company’s pension obligations within the next financial year for the UK plan. Any differences
between these assumptions and the actual outcome will also affect future net income and net assets.
The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and
obligation used are provided in Note 4.
Income taxes
Income tax expense represents the sum of current tax and deferred tax.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in
equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is
determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are
taxable or deductible in other periods as well as items that are never taxable or deductible. The company’s liability for current tax is calculated using tax
rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on temporary differences at the balance sheet date between the tax bases of assets and liabilities
and their carrying amounts for financial reporting purposes. Deferred tax liabilities are recognized for taxable temporary differences.
Deferred tax assets are only recognized to the extent that it is probable that they will be realized in the future.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is
settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities
are not discounted. See Note 6 for further details.
Financial assets
Financial assets are recognized initially at fair value, normally being the transaction price. In the case of financial assets not at fair value through profit or
loss, directly attributable transaction costs are also included. The subsequent measurement of financial assets depends on their classification, as set
out below. The company derecognizes financial assets when the contractual rights to the cash flows expire or the rights to receive cash flows have
been transferred to a third party along with substantially all of the risks and rewards or control of the asset.This includes the derecognition of
receivables for which discounting arrangements are entered into.
Financial assets measured at amortized cost
Financial assets are classified as measured at amortized cost when they are held in a business model the objective of which is to collect contractual
cash flows and the contractual cash flows represent solely payments of principal and interest. Such assets are carried at amortized cost using the
effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the assets are derecognized
or impaired and when interest is recognized using the effective interest method. This category of financial assets includes trade and other receivables.
Cash equivalents
Cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of
changes in value and generally have a maturity of three months or less from the date of acquisition. Cash equivalents are classified as financial assets
measured at amortized cost.
Financial liabilities
All financial liabilities held by the company are classified as financial liabilities measured at amortized cost. Financial liabilities include other payables,
accruals, and finance debt. The company determines the classification of its financial liabilities at initial recognition.
Financial liabilities measured at amortized cost
All financial liabilities are initially recognized at fair value, net of directly attributable transaction costs. For interest-bearing loans and borrowings this is
typically equivalent to the fair value of the proceeds received, net of issue costs associated with the borrowing.
After initial recognition, financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is
calculated by taking into account any issue costs and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or
cancellation of liabilities are recognized in interest and other income and finance costs respectively.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
264
bp Annual Report and Form 20-F 2020
1. Significant accounting policies, judgements, estimates and assumptions – continued
Impact of new International Financial Reporting Standards
The company adopted ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial instruments’ and IFRS 7 ‘Financial instruments:
Disclosures'’ with effect from 1 January 2020. The adoption of ‘Interest Rate Benchmark Reform – Phase I – Amendments to IFRS 9 ‘Financial
instruments’ and IFRS 7 ‘Financial instruments: Disclosures’ has had no material impact on the company's financial statements. There are no other new
or amended standards or interpretations adopted during the year that have a significant impact on the financial statements.
Financial statements
2. Investments
Cost
At 1 January 2020
Additions
Disposals
At 31 December 2020
Amounts provided
At 1 January 2020
Additions
At 31 December 2020
Cost
At 1 January 2019
Additions
Disposals
At 31 December 2019
Amounts provided
At 1 January 2019
At 31 December 2019
At 31 December 2020
At 31 December 2019
Subsidiaries
Associates
Shares
Shares
Total
$ million
166,287
—
(2)
166,285
33
5,710
5,743
166,302
—
(15)
166,287
33
33
160,542
166,254
2
—
—
2
—
—
—
2
—
—
2
—
—
2
2
166,289
—
(2)
166,287
33
5,710
5,743
166,304
—
(15)
166,289
33
33
160,544
166,256
At 31 December 2020, the carrying amount of the company’s net assets of $112.6 billion exceeded the group’s market capitalisation of $70.5 billion.
This is identified by IAS 36 Impairment of Assets as an indicator that assets may be impaired.
Management’s best estimate oil and natural gas price assumptions for value-in-use impairment testing were revised downwards during 2020 and the
period covered extended to 2050. Management also undertook a re-assessment of expectations to extract value from certain exploration prospects as
a result of a review of the group's long-term strategic plan. As a result, management performed a review of the carrying value of the company’s major
investments to identify potential impairment triggers, in line with the requirements of IAS 36 Impairment of Assets. Potential indicators of impairment
were identified in those subsidiaries which hold, or whose own investments hold, significant Upstream assets, requiring further tests to be performed.
The cash generating units assessed were considered to be each investment holding company chain (defined as each direct subsidiary and its own
investments), as this is judged to be the smallest identifiable group of assets from the company’s perspective that generates cash inflows that are
largely independent of the cash inflows from other assets or groups of assets. Further tests were performed on BP International Ltd (BPI), BP Holdings
North America Ltd (BPHNA) and BP Holdings Canada Ltd.
A recoverable amount for each investment company holding chain was calculated based on the value in use cash flows from Upstream and
Downstream goodwill impairment calculations, combined with additional sources of uplift in value identified. The value in use tests used the present
value of pre-tax cash flows discounted using a pre-tax rate which varies depending on the country of operation of the underlying assets.
Upstream
For Upstream assets held by the company’s subsidiaries, the value in use is based on the cash flows expected to be generated by the projected oil or
natural gas production profiles up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and
resources, appropriately risked.
As the production profile and related cash flows can be estimated from bp’s past experience, management believes that the cash flows generated over
the estimated life of field is the appropriate basis upon which to assess assets for impairment. The estimated date of cessation of production depends
on the interaction of a number of variables, such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of
the development of the infrastructure necessary to recover the hydrocarbons, production costs, the contractual duration of the production concession
and the selling price of the hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash
flows of each field is computed using appropriate individual economic models and key assumptions agreed by bp management.
Estimated production volumes and cash flows up to the date of cessation of production on a field-by-field basis, including operating and capital
expenditure, are derived from the business segment plan. The production profiles used are consistent with the reserve and resource volumes approved
as part of bp’s centrally controlled process for the estimation of proved and probable reserves and total resources.
The key assumptions used in the value-in-use calculation are oil and natural gas prices, production volumes and the discount rate. Oil and gas price
assumptions and discount rate assumptions used were as disclosed in Note 1.
Due to economic developments, regulatory change and emissions reduction activity arising from climate concern and other factors, future commodity
prices and other assumptions may differ from the forecasts used in the calculations.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
265
2. Investments – continued
The Upstream impairment review on BPHNA assets calculated that a 10% price increase would add $1,780 million to the value of the assets, while a
10% price reduction would result in a $2,728 million reduction. A 1% increase in discount rate would likely generate a reduction in the value of assets
of $796 million, while a 1% reduction in the rate would have increased the value by $1,151 million.
The Upstream impairment review on BPI assets calculated that a 10% price increase would add $2,032 million to the value of the assets, while a 10%
price reduction would result in a $3,741 million reduction. A 1% increase in discount rate would likely generate a reduction in the value of assets of
$1,467 million, while a 1% reduction in the rate would have increased the value by $1,365 million.
The Upstream impairment review on BP Holdings Canada assets calculated that a 10% price increase would add $574 million to the value of the
assets, while a 10% price reduction would result in a $574 million reduction. A 1% increase in discount rate would likely generate a reduction in the
value of assets of $178 million, while a 1% reduction in the rate would have increased the value by $204 million.
These price sensitivity analyses do not, however, represent management’s best estimate of any impairment charges or reversals that might be
recognized as they do not fully incorporate consequential changes that may arise, such as changes in costs and business plans and phasing of
development. For example, costs across the industry are more likely to decrease as oil and natural gas prices fall. The above sensitivity analyses
therefore do not reflect a linear relationship between revenue and value that can be extrapolated. The interdependency of these inputs and risk factors
plus the diverse characteristics of Upstream oil and gas properties limits the practicability of estimating the probability or extent to which the overall
recoverable amount is impacted by changes to the price assumptions or production volumes.
Downstream
Recoverable amounts for BPHNA also included the value of key Downstream assets held by the refinery, midstream and retail businesses. For the
Downstream, cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up to five years. To
determine the value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted at an 8% pre-tax rate and
aggregated with a terminal value.
Discount rates are a key assumption in the value-in-use calculations for the downstream businesses. A 1% increase in discount rate would likely
generate a reduction in the value of assets of $2,200 million, while a 1% reduction in the rate would have increased the value by $2,200 million.
Other
The valuation of BPI also included the Upstream activity of the company’s equity-accounted investment in Rosneft.
The BPI and BPHNA investment holding chains include the bp group’s Oil and Gas trading function. These have been included in the valuation based on
a multiple of underlying replacement cost profit.
Conclusions for Investment holding company chains
As a result of this review, the company has recognized total impairment charges of $5,710 million (2019 $nil) against its investments. Impairments
were calculated on a value in use basis, applying discount rates of 8% to investments in North America and a weighted average rate of 11% overall.
Charges of $2,565 million related to Upstream investments in Canada held through BP Holdings Canada Ltd. Impairments of $2,638 million were
recognized against the BPHNA investment holding chain and $507 million against the BPI investment holding chain.
The residual value of the investment holding chains which have recognized impairment charges during the year was $138,688 million.
The more important subsidiaries of the company at 31 December 2020 and the percentage holding of ordinary share capital (to the nearest whole
number) are set out below. For a full list of related undertakings see Note 14.
Subsidiaries
International
BP Global Investments
BP International
Burmah Castrol
Canada
BP Holdings Canada
US
% Country of incorporation
Principal activities
100 England & Wales
100 England & Wales
100 Scotland
Investment holding
Integrated oil operations
Lubricants
100 England & Wales
Investment holding
BP Holdings North America
100 England & Wales
Investment holding
The carrying value of the investment in BP International Limited at 31 December 2020 was $75,645 million (2019 $76,152 million).
3. Receivables
Amounts receivable from subsidiariesa
Amounts receivable from associates
Current
284
7
291
2020
Non-current
3,174
—
3,174
$ million
2019
Non-current
2,771
—
2,771
Current
134
1
135
a Non-current receivables includes a promissory note issued by BP (Abu Dhabi) Limited in 2016 in consideration for the issue of BP p.l.c. ordinary shares to the government of Abu Dhabi.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
266
bp Annual Report and Form 20-F 2020
Financial statements
4. Pensions
The primary pension arrangement is a funded final salary pension plan in the UK under which retired employees draw the majority of their benefit as an
annuity. This pension plan is governed by a corporate trustee whose board is composed of four member-nominated directors, four company-nominated
directors, an independent director, and an independent chairman nominated by the company. The trustee board is required by law to act in the best
interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan. The plan is closed to new joiners
and is currently under consultation for closure to future accrual. As at 31 December 2020, it remains open to ongoing accrual for current members.
New joiners are eligible for membership of a defined contribution plan.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due.
During 2020 the aggregate level of contributions was $189 million (2019 $236 million). The aggregate level of contributions in 2021 is expected to be
approximately $180 million, and includes contributions we expect to be required to make by law or under contractual agreements, as well as an
allowance for discretionary funding.
For the primary UK plan there is a funding agreement between the company and the trustee. On an annual basis a schedule of contributions is agreed
covering the next five years. Contractually committed funding amounted to $1,014 million at 31 December 2020, all of which relates to future service.
The surplus relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any
remaining assets once all members have left the plan.
The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most recent
actuarial review was 31 December 2020. The principal plans are subject to a formal actuarial valuation every three years in the UK. The most recent
formal actuarial valuation of the main pension plan was as at 31 December 2017 and a valuation as at 31 December 2020 is currently under way.
The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions are reviewed by
management at the end of each year and are used to evaluate accrued pension benefits at 31 December and pension expense for the following year.
Financial assumptions used to determine benefit obligation
Discount rate for pension plan liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inflation for pension plan liabilities
Financial assumptions used to determine benefit expense
Discount rate for pension plan service costs
Discount rate for pension plan other finance expense
Inflation for pension plan service costs
2020
1.4
3.6
2.8
2.8
2.9
2020
2.1
2.1
2.6
%
2019
2.1
3.4
2.7
2.7
2.7
%
2019
3.0
2.9
3.1
The discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the expected
benefit payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long-term government
bonds. The inflation assumption is used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions.
The assumption for the rate of increase in salaries is based on our inflation assumption plus an allowance for expected long-term real salary growth.
This comprises of an allowance for promotion-related salary growth of 0.7%.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best
practice in the UK and have been chosen with regard to the latest available published tables adjusted to reflect the experience of the plans and an
extrapolation of past longevity improvements into the future. For the main pension plan the mortality assumptions are as follows:
Mortality assumptions
Life expectancy at age 60 for a male currently aged 60
Life expectancy at age 60 for a male currently aged 40
Life expectancy at age 60 for a female currently aged 60
Life expectancy at age 60 for a female currently aged 40
2020
26.9
28.4
28.8
30.4
Years
2019
27.3
28.9
28.7
30.5
The assets of the primary plan are held in a trust, the primary objective of which is to accumulate pools of assets sufficient to meet the obligations of
the plan. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio
management.
A proportion of the assets are held in equities, owing to a higher expected level of return over the long term of such assets with an acceptable level of
risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the
investment portfolios are highly diversified.
The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way as the
plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment (LDI) approach
for part of the portfolio, investing primarily in government bonds to achieve this matching effect for the most significant plan liability assumptions of
interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using existing
bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further bonds to
increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan assets in the
table below.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
267
4. Pensions – continued
For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets with liability matching characteristics over
time primarily by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. During 2020, the plan switched
11% from equities to bonds (2019 2%).
The company’s asset allocation policy for the primary plan is as follows:
Asset category
Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate
%
17
76
7
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2020 were $4,217 million (2019 $4,804 million) of
government-issued nominal bonds and $24,576 million (2019 $19,462 million) of index-linked bonds.
The primary plan does not invest directly in either securities or property/real estate of the company or of any subsidiary.
The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the
effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 269.
Fair value of pension plan assets
Listed equities
– developed markets
– emerging markets
Private equitya
Government issued nominal bondsb
Government issued index-linked bondsb
Corporate bondsb
Propertyc
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
2020
5,008
418
2,899
4,303
24,576
8,906
2,553
1,392
795
(9,387)
41,463
a Private equity is valued at fair value based on the most recent third-party net asset, revenue or earnings based valuations that generally result in the use of significant unobservable inputs.
b Bonds held are denominated in sterling and valued using quoted prices in active markets.
c Property held is all located in the United Kingdom and is valued based on an analysis of recent market transactions supported by market knowledge derived from third-party valuers.
Analysis of the amount charged to profit or loss
Current service costa
Past service incomeb
Operating charge relating to defined benefit plans
Payments to defined contribution plan
Total operating charge
Interest income on plan assetsc
Interest on plan liabilities
Other finance (income)
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on pension plan assets
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of plan liabilities
Experience gains and losses arising on the plan liabilities
Remeasurements recognized in other comprehensive income
2020
250
(48)
202
49
251
(724)
595
(129)
4,108
(4,205)
585
54
542
a The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are included in current service cost.
b Past service income represents curtailment gains arising from restructuring programmes.
c The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
$ million
2019
6,285
1,096
2,675
4,884
19,462
6,132
2,507
426
98
(7,436)
36,129
$ million
2019
227
2
229
42
271
(909)
756
(153)
2,945
(2,292)
136
(57)
732
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
268
bp Annual Report and Form 20-F 2020
4. Pensions – continued
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Operating charge relating to defined benefit plans
Interest cost
Contributions by plan participantsa
Benefit payments (funded plans)b
Benefit payments (unfunded plans)b
Remeasurements
Benefit obligation at 31 December
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsc
Contributions by plan participantsa
Contributions by employers (funded plans)
Benefit payments (funded plans)b
Remeasurementsc
Fair value of plan assets at 31 Decemberd e
Surplus at 31 December
Represented by
Asset recognized
Liability recognized
The surplus may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded plans as follows
Funded
Unfunded
Financial statements
2020
29,743
1,302
202
595
21
(1,291)
(6)
3,566
34,132
36,129
1,583
724
21
189
(1,291)
4,108
41,463
7,331
7,567
(236)
7,331
7,564
(233)
7,331
$ million
2019
26,796
941
229
756
20
(1,207)
(5)
2,213
29,743
32,085
1,141
909
20
236
(1,207)
2,945
36,129
6,386
6,588
(202)
6,386
6,588
(202)
6,386
(33,899)
(233)
(34,132)
(29,541)
(202)
(29,743)
a Most of the contributions made by plan participants were made under salary sacrifice.
b The benefit payments amount shown above comprises $1,280 million benefits (2019 $1,194 million) plus $17 million (2019 $18 million) of plan expenses incurred in the administration of the benefit.
c The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
d Reflects $41,088 million of assets held in the BP Pension Fund (2019 $35,811 million) and $306 million held in the BP Global Pension Trust (2019 $251 million), as well as $53 million representing the
company’s share of Merchant Navy Officers Pension Fund (2019 $53 million) and $16 million of Merchant Navy Ratings Pension Fund (2019 $14 million).
e The fair value of plan assets includes borrowings related to the LDI programme as described on page 268.
Sensitivity analysis
The discount rate, inflation, salary growth and the mortality assumptions all have a significant effect on the amounts reported. A one-percentage point
change, in isolation, in certain assumptions as at 31 December 2020 for the company’s plans would have had the effects shown in the table below. The
effects shown for the expense in 2021 comprise the total of current service cost and net finance income or expense.
Discount ratea
Effect on pension expense in 2021
Effect on pension obligation at 31 December 2020
Inflation rateb
Effect on pension expense in 2021
Effect on pension obligation at 31 December 2020
Salary growth
Effect on pension expense in 2021
Effect on pension obligation at 31 December 2020
$ million
One percentage point
Increase
Decrease
(275)
(5,653)
198
7,685
145
5,337
(116)
(4,482)
31
670
(27)
(585)
a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.
One additional year of longevity in the mortality assumptions would increase the 2021 pension expense by $28 million and the pension obligation at
31 December 2020 by $1,403 million.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
269
4. Pensions – continued
Estimated future benefit payments and the weighted average duration of defined benefit obligations
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2030 and the weighted
average duration of the defined benefit obligations at 31 December 2020 are as follows:
Estimated future benefit payments
2021
2022
2023
2024
2025
2026-2030
Weighted average duration
5. Payables
Amounts payable to subsidiaries
Accruals
Other payables
$ million
1,070
1,084
1,118
1,139
1,133
5,929
Years
19.2
Current
27,933
2
76
28,011
2020
Non-current
28,060
—
24
28,084
$ million
2019
Non-current
31,894
—
33
31,927
Current
17,916
21
70
18,007
Included in current amounts payable to subsidiaries is an interest-bearing payable of $4,236 million (2019 $4,236 million) with BP International Limited,
with interest being charged based on a 3-month USD LIBOR rate plus 55 basis points and a maturity date of December 2021. Also included in current
amounts payable is an interest-bearing payable of $5,033 million (2019 $5,031 million) with BP Finance plc. On 30 April 2020 the facility was renewed
for 10 years until 30 April 2030 with interest being charged based on a 3-month USD LIBOR rate minus 0.14%. Though due in 2030, the loan is
repayable to BP Finance plc at one business days notice. Non-current amounts payable to subsidiaries includes an interest-bearing payable of $27,100
million (2019 $27,100 million) with BP International Limited, with interest being charged based on a 3-month USD LIBOR rate plus 65 basis points and a
maturity date of May 2023.
Current liabilities of $27,933m are payable to wholly owned subsidiaries of the company within the bp group. As such, the company has control over
whether these balances can be called in by the counterparties. Though the $5,033 million loan from BP Finance plc can be called at one business days
notice, this loan is recorded as a non-current receivable in the financial statements of BP Finance plc, since the counterparty has no intent to call the
loan at short notice. The balance of $4,236 million payable to BP International Ltd is due in December 2021, though it is the intent of management to
extend this amount into a longer term loan. The company also has current liabilities of $18,652 million on Internal Funding Accounts (IFAs) payable to
BP International Ltd. Whilst IFA credit balances are legally repayable on demand, in practice they have no termination date. These balances form a key
part of the bp group’s liquidity and funding arrangements under its centralised treasury funding model. The bp group regularly looks to optimize its
funding position, as part of which management will consider whether any part of these IFA balances should be converted into longer term loans, or
maintained as current payables.
The maturity profile of the financial liabilities included in the balance sheet at 31 December is shown in the table below. These amounts are included
within payables.
Due within
1 to 2 years
2 to 5 years
More than 5 years
2020
30
27,259
795
28,084
$ million
2019
48
31,499
380
31,927
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
270
bp Annual Report and Form 20-F 2020
6. Taxation
Tax charge included in total comprehensive income
Deferred tax
Origination and reversal of temporary differences in the current year
This comprises:
Taxable temporary differences relating to pensions
Deferred tax
Deferred tax liability
Pensions
Net deferred tax liability
Analysis of movements during the year
At 1 January
Charge (credit) for the year in the income statement
Charge (credit) for the year in other comprehensive income
At 31 December
Financial statements
2020
338
338
2,631
2,631
2,293
44
294
2,631
$ million
2019
389
389
2,293
2,293
1,907
55
331
2,293
At 31 December 2020, deferred tax assets of $375 million on other temporary differences; $12 million relating to pensions, $75 million relating to
income losses and $288 million relating to other deductible temporary differences (2019 $391 million relating to other deductible temporary differences,
$67 million relating to income losses and $9 million relating to pensions) were not recognised as it is not considered probable that suitable taxable
profits will be available in the company from which the future reversal of the underlying temporary differences can be deducted. There is no fixed expiry
date for the unrecognised temporary differences.
7. Called-up share capital
The allotted, called-up and fully paid share capital at 31 December was as follows:
Issued
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share-based payment plans
Repurchase of ordinary share capital
At 31 December
Shares
thousand
7,233
5,473
21,535,840
—
34,000
(120,058)
21,449,782
2020
$ million
12
9
21
Shares
thousand
7,233
5,473
—
9
(30)
5,383 21,525,464
208,927
37,400
(235,951)
5,362 21,535,840
5,383
2019
$ million
12
9
21
5,381
52
9
(59)
5,383
5,404
a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference
shares.
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for
every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on
other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding-up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference
shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the
preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over
par value.
During 2020 the company repurchased 120 million ordinary shares at a cost of $776 million, including transaction costs of $4 million, as part of the
share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares represented 0.6%
of ordinary share capital.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
271
7. Called-up share capital – continued
Treasury sharesa
At 1 January
Purchases for settlement of employee share plans
Issue of new shares for employee share-based payment plans
Shares re-issued for employee share-based payment plans
At 31 December
Of which - shares held in treasury by bp
- shares held in ESOP trusts
- shares held by bp’s US plan administratorb
a See Note 8 for definition of treasury shares.
b Held by the company in the form of ADSs to meet the requirements of employee share-based payment plans in the US.
2020
Shares
thousand
Nominal value
$ million
Shares
thousand
1,296,856
—
34,116
(143,322)
1,187,650
1,105,157
82,491
2
323 1,426,265
1,118
—
37,400
9
(167,927)
(36)
296 1,296,856
275 1,163,077
133,707
72
21
—
2019
Nominal value
$ million
356
—
9
(42)
323
290
33
—
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by bp during the year, representing 5.4%
(2019 5.9%) of the called-up ordinary share capital of the company.
During 2020, the movement in shares held in treasury by bp represented less than 0.3% (2019 less than 0.5%) of the ordinary share capital of the
company.
8. Capital and reserves
See statement of changes in equity for details of all reserves balances.
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury
shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in
an acquisition made by the issue of shares.
Treasury shares
Treasury shares represent bp shares repurchased and available for specific and limited purposes. For accounting purposes, shares held in Employee
Share Ownership Plans (ESOPs) and by bp’s US share plan administrator to meet the future requirements of the employee share-based payment plans
are treated in the same manner as treasury shares and are, therefore, included in the financial statements as treasury shares. The ESOPs are funded by
the company and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the shares held by the
ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity. Assets and liabilities of the
ESOPs are recognized as assets and liabilities of the company.
Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial information of the foreign currency
branch. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the company.
The profit and loss account reserve includes $23,600 million (2019 $24,107 million), the distribution of which is limited by statutory or other restrictions.
The financial statements for the year ended 31 December 2020 do not reflect the dividend announced on 2 February 2021 which will be paid in March
2021; this will be treated as an appropriation of profit in the year ended 31 December 2021.
9. Financial guarantees
The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2020 were $80,891 million (2019 $78,586 million),
the majority of which relate to finance debt of subsidiaries. Also included are guarantees of subsidiaries' liabilities under the Consent Decree between
the United States, the Gulf states and bp and under the settlement agreement with the Gulf states in relation to the Gulf of Mexico oil spill. The
company has also issued uncapped indemnities and guarantees, including a guarantee of subsidiaries’ liabilities under the Plaintiffs' Steering
Committee agreement relating to the Gulf of Mexico oil spill. See note 33 in the consolidated group financial statements of BP p.l.c. for further
information.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
272
bp Annual Report and Form 20-F 2020
10. Share-based payments
Effect of share-based payment transactions on the company’s result and financial position
Total expense recognized for equity-settled share-based payment transactions
Total (credit) expense recognized for cash-settled share-based payment transactions
Total expense recognized for share-based payment transactions
Closing balance of liability for cash-settled share-based payment transactions
Total intrinsic value for vested cash-settled share-based payments
Financial statements
2020
491
(13)
478
1
—
$ million
2019
433
(1)
432
17
16
Additional information on the company’s share-based payment plans is provided in Note 11 to the consolidated financial statements.
11. Auditor’s remuneration
Note 36 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a group basis.
12. Directors’ remuneration
Remuneration of directors
Total for all directors
Emoluments
Amounts awarded under incentive schemesa
Total
a Excludes amounts relating to past directors.
2020
6
14
20
$ million
2019
9
20
29
Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits
earned during the relevant financial year, plus cash bonuses awarded for the year. Further information is provided in the Directors’ remuneration report
on page 103.
13. Employee costs and numbers
Employee costsa
Wages and salaries
Social security costs
Pension costs
Average number of employees
Upstream
Downstream
Other businesses and corporate
2020
814
119
90
1,023
2020
312
1,213
2,307
3,832
$ million
2019
597
107
80
784
2019
279
1,142
2,300
3,721
a Comparative information has been restated due the correction of an accounting error.
The employee costs noted above relate to those employees with contracts of employment in the name of BP p.l.c.. These costs are borne by other
undertakings within the group.
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
273
14. Related undertakings of the group
In accordance with Section 409 of the Companies Act 2006, a full list of related undertakings, the registered office address and the percentage of
equity owned as at 31 December 2020 is disclosed below.
Unless otherwise stated, the share capital disclosed comprises ordinary shares or common stock (or local equivalent thereof) which are indirectly held
by BP p.l.c.
All subsidiary undertakings are controlled by the group and their results are fully consolidated in the group’s financial statements.
The percentage of equity owned by the group is 100% unless otherwise noted below.
The stated ownership percentages represent the effective equity owned by the group.
Subsidiaries
200 PS Overseas Holdings Inc.
563916 Alberta Ltd. (99.90%)a
ACP (Malaysia), Inc.
Actomat B.V.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
240 - 4th Avenue SW, Calgary AB T2P 4H4, Canada
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Advance Petroleum Holdings Pty Ltd
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Advance Petroleum Pty Ltd
AE Cedar Creek Holdings LLCb
AE Goshen II Holdings LLCb
AE Goshen II Wind Farm LLCb
AE Power Services LLCb
AE Wind PartsCo LLCb
Air BP Albania SHA
Air BP Brasil Ltda.
Air BP Canada LLCb
Air BP Croatia d.o.o.
Air BP Finland Oy
Air BP Iceland
Air BP Limited
Air BP Norway AS
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Air BP Albania Sh.A., Aeroporti Nderkombetar i Tiranes, “Nene Tereza”, Post Box 2933 in Tirana, Albania
Avenida Rouxinol, 55 , Offices 501-514 , Moema Office Tower, São Paulo, 04516 - 000, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Savska cesta 32, Zagreb, Croatia
Öljytie 4, 01530 Vantaa, Finland
Skogarhlid 12, 105, Reykjavik, Iceland
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Tjuvholmen allé, Oslo, 0252, Norway
Air BP Sales Romania S.R.L.
59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania
Air BP Sweden AB
Air Refuel Pty Ltdc
Allgreen Pty Ltd
AM/PM International Inc.
American Oil Company
Amoco (Fiddich) Limited
Amoco (U.K.) Exploration Company, LLCb
Amoco Bolivia Services Company Inc.
Box 8107, 10420, Stockholm, Sweden
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
Amoco Canada International Holdings B.V.
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Amoco Capline Pipeline Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Chemical (Europe) S.A.
Amoco Chemicals (FSC) B.V.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Amoco Cypress Pipeline Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Destin Pipeline Company
Amoco Environmental Services Companyd
Amoco Exploration Holdings B.V.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Bank of America Center, 16th Floor, 1111 East Main Street, Richmond VA 23219, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Amoco Guatemala Petroleum Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco International Finance Corporation
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco International Petroleum Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Louisiana Fractionator Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Main Pass Gathering Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Marketing Environmental Services Company
400 East Court Avenue, Des Moines ID 50309, United States
Amoco MB Fractionation Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco MBF Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Netherlands Petroleum Company
Amoco Nigeria Exploration Company Limitede
Amoco Nigeria Oil Company Limited
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria
188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria
Amoco Nigeria Petroleum Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Nigeria Petroleum Company Limited
188, Awolowo Road, S. W. Ikoyi, Lagos, Nigeria
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
274
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
Amoco Norway Oil Company
Amoco Oil Holding Company
Amoco Olefins Corporation
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Overseas Exploration Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Pipeline Asset Company
Amoco Pipeline Holding Company
Amoco Properties Incorporated
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Remediation Management Services Corporation
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Research Operating Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Rio Grande Pipeline Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Somalia Petroleum Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Sulfur Recovery Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco Trinidad Gas B.V.
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Amoco Tri-States NGL Pipeline Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Amoco U.K. Petroleum Limited
AmProp Finance Company
Amprop Illinois I Limited Partnershipf
Amprop, Inc.
Anaconda Arizona, Inc.
Arabian Production And Marketing Lubricants Company
(50.00%)
Aral Aktiengesellschaft
Aral Luxembourg S.A.
Aral Services Luxembourg Sarl
Aral Tankstellen Services Sarl
ARCO British International, Inc.
ARCO British Limited, LLCb
ARCO Coal Australia Inc.
ARCO El-Djazair Holdings Inc.
ARCO Environmental Remediation, L.L.C.b
ARCO Gaviota Company
ARCO International Investments Inc.
ARCO Midcon LLCb
ARCO Oil Company Nigeria Unlimitedb
ARCO Resources Limited
ARCO Trinidad Exploration and Production Company
Limited
ARCO Unimar Holdings LLCb
Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
801 Adlai Stevenson Drive, Springfield, IL, 62703, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Riyadh Airport Road, Business Gate, Building C2, 2nd Floor. , Saudi Arabia
Wittener Straße 45, 44789 Bochum, Germany
Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg
Autoroute A3/E25, L-3325 Berchem Ouest, Luxembourg
Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
8/10, Broad Street, Lagos, Nigeria
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
2 Bayside Executive Park, West Bay, Nassau, Bahamas
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur,
Malaysia
Atlantic 2/3 UK Holdings Limited
Atlantic Richfield Companyd
Autino Holdings Limited (88.85%)g
Autino Limited (88.85%)
Auwahi Wind Energy Holdings LLCb
B2Mobility GmbH
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Abbey Gardens, 7th Floor, 4 Abbey Street, Reading, RG1 3BA, United Kingdom
Abbey Gardens, 7th Floor, 4 Abbey Street, Reading, RG1 3BA, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Wittener Straße 45, 44789 Bochum, Germany
Bahia de Bizkaia Electridad, S.L. (75.00%)
Atraque Punta Lucero, Explanada Punta Ceballos s/n, Ziérbena (Vizcaya), Spain
Baltimore Ennis Land Company, Inc.
4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States
BASS Management Pty Ltd (51.00%)
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
BASS NZ Head Trust (51.00%)
BASS NZ Management Pty Ltd
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
BASS NZ Sub Management Pty Ltd
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
BASS NZ Sub Trust (51.00%)
BE LAMBDA-ENA GmbH
Black Lake Pipe Line Company
BP - Castrol (Thailand) Limited (59.81%)h
BP (Abu Dhabi) Limited
BP (Barbados) Holding SRL
BP (Barbican) Limitedi
BP (China) Holdings Limitedb
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Donau-City-Straße 7, 1220, Wien, Austria
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa South Sathon, Bangkok 10120, Thailand
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Erin Court, Bishop's Court Hill, St. Michael , Barbados
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Room 2101, 21F Youyou International Plaza, 76 Pujian Road, Pudong, Shanghai Pilot Free Trade Zone, PRC
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
275
14. Related undertakings of the group – continued
BP (China) Industrial Lubricants Limitedb
BP (Gibraltar) Limitedj
BP (GTA Mauritania) Finance Limited
BP (GTA Senegal) Finance Limited
BP (Guangzhou) Advanced Mobility Limitedb
BP (Hunan) Petroleum Company Limitedb
BP (Indian Agencies) Limitedi
BP (Shandong) Petroleum Co., Ltdb
BP (Shanghai) Trading Limitedb
No.9 Bin Jiang South Road, Petrochemical Industrial Park, Taicang Gangkou Development Zone, Jiangsu
Province, China
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Room 1218, Building 3, No. 6 Hanxing San jie, Zhongcun Street, Panyu District, Guangzhou, Guangdong
Province , China
Room 1001, 10th Floor, Building A2, Xiangjiang Times Business Square, No.179 Xiandao Road, Yuelu District,
Changsha, Hunan, China
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Room 1-2201, Sijian Meilin Mansion, No. 48-15 Wuyingshan Middle Road, Tianqiao District, Ji'nan, Shandong,
China
Room 2105, No. 28 Maji Road, Donghua Financial Building, China (Shanghai) Pilot Free Trade, Shanghai,
200131, China
BP Absheron Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Advanced Mobility Limited
BP Africa Limitedi
BP Africa Oil Limited
BP Akaryakit Ortakligi (70.00%)f
BP Alternative Energy Holdings Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Degirmen Yolu Cad. No:28 Asia Ofis Park K:3 , Icerenky - Atasehir, Istanbul, 34752, Turkey
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Alternative Energy Investments Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Alternative Energy North America Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Alternative Energy Trinidad and Tobago Limited
5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago
BP America Chemicals Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP America Foreign Investments Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP America Inc.
BP America Limited
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP America Production Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP AMI Leasing, Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Amoco Chemical Malaysia Holding Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Amoco Exploration (Faroes) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Amoco Exploration (In Amenas) Limited
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
BP Andaman II Ltd
BP Angola (Block 18) B.V.
BP Argentina Exploration Company
BP Argentina Holdings LLCb
BP Asia Pacific Holdings Limited
BP Asia Pacific Pte Ltdi
BP Australia Employee Share Plan Proprietary Limited
BP Australia Group Pty Ltde
BP Australia Investments Pty Ltd
BP Australia Pty Ltd
BP Australia Shipping Pty Ltdk
BP Australia Swaps Management Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Aviation A/S
c/o Danish Refuelling Services I/S, Hydrantvej 16, 2770 Kastrup, Denmark
BP Aviation Infrastructure Pty Ltd
BP Benevolent Fund Trustees Limitedi
BP Berau Ltd.
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Biocombustíveis S.A. (96.53%)
Avenida das Nações Unidas, 12399, 4fl, Sao Paulo, Brazil
BP Biofuels Advanced Technology Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Biofuels Brazil Investments Limited
BP Biofuels North America LLCb
BP Biofuels Trading Comércio, Importação e Exportação
Ltda. (48.27%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida das Nações Unidas, 12.399 , 4º andar, cj. 41B, sala 01, São Paulo, Brazil
BP Bomberai Ltd.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Brasil Ltda.
BP Brazil Tracking L.L.C.b
BP Bulwer Island Pty Ltdl
BP Business Service Centre Asia Sdn Bhd
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur,
Malaysia
BP Business Service Centre KFTb
BP Business Service Centre KFT, 32-34 Soroksári út, H-1095 Budapest, Hungary
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
276
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
BP Business Solutions India Private Limited
71 & 73, 7th Floor, Maker Maxity Bandra Kurla Complex, Bandra (East), Bandra Suburban, Mumbai, 400051,
India
BP Canada Energy Development Company
Stewart McKelvey, Attention: Lawrence J. Stordy, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada
BP Canada Energy Group ULC
Stewart McKelvey, Attention: Lawrence J. Stordy, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada
BP Canada Energy Marketing Corp.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Canada International Holdings B.V.
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
BP Canada Investments Inc.
BP Capellen Sarl
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Aire de Capellen, L-8309 Capellen, Luxembourg
BP Capital Markets America Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Capital Markets p.l.c.
BP Car Fleet Limitedi
BP Caribbean Company
BP Castrol KK (64.84%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
East Tower 20F, Gate City Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan
BP Castrol Lubricants (Malaysia) Sdn. Bhd. (63.03%)
Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur,
Malaysia
BP CCUS UK LTD
BP Central Pipelines LLCb
BP Chemical Remediation Holdings LLCb
BP Chemicals East China Investments Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Chemicals Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP China Exploration and Production Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Comercializadora de Energia Ltda.
Avenida das Nações Unidas, 12399, rooms 62,63 and 64 size B, 6th floor, Landmark Building, São Paulo,
04578-000, Brazil
BP Commodities Trading Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Commodity Supply B.V.
BP Company North America Inc.m
BP Containment Response Limited
BP Containment Response System Holdings LLCb
BP Continental Holdings Limited
BP Corporate Holdings Limited
BP Corporation North America Inc.
BP D230 Limited
BP Danmark A/S
BP D-B Pipeline Company LLC (54.37%)f
BP Developments Australia Pty. Ltd.
BP Dogal Gaz Ticaret Anonim Sirketi
BP East Kalimantan CBM Limited
BP Eastern Mediterranean Limited
BP Egypt Company
BP Egypt East Delta Marine Corporationd
BP Egypt East Tanka B.V.
BP Egypt Production B.V.
BP Egypt Ras El Barr B.V.
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
150 West Market Street, Suite 800, Indianapolis IN 46204, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Orestads Boulevard 73, 2300, Kobenhavn S, Denmark
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 15, 240 St Georges Terrace, Perth WA 6000, Australia
Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
BP Egypt West Mediterranean (Block B) B.V.
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
BP Energía México, S. de R.L. de C.V.
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
BP Energy Asia Pte. Limited
BP Energy Colombia Limited
BP Energy Company
BP Energy do Brasil Ltda.
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
BP Energy Europe Limited
BP Energy Retail LLCb
BP Energy Solutions B.V.
BP Espana, S.A. Unipersonaln
BP Estaciones y Servicios Energéticos, Sociedad Anónima
de Capital Variablec
BP Europa SEo
BP Exploracion de Venezuela S.A.
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Avenida de Barajas 30, Madrid, Madrid, Spain
Avenida Santa Fe 505, Piso 10, Distrito Federal , MEXICO C.P. 0534, Mexico
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
Av. Francisco de Miranda, con primera avenida de Los Palos , Grandes, Edif Cavendes, piso 9, ofi 903, Los
Palos Grandes, Chacao / Caracas, Caracas / Miranda, 1060, Venezuela, Bolivarian Republic of
BP Exploration & Production Inc.d
BP Exploration (Absheron) Limited
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
277
14. Related undertakings of the group – continued
BP Exploration (Algeria) Limited
BP Exploration (Alpha) Limited
BP Exploration (Angola) Limited
BP Exploration (Azerbaijan) Limited
BP Exploration (Canada) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (Caspian Sea) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (D230) Limited
BP Exploration (Delta) Limited
BP Exploration (El Djazair) Limited
BP Exploration (Epsilon) Limited
BP Exploration (Gambia) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
PricewaterhouseCoopers (Bahamas) Limited, Providence House, East Hill Street, P.O. Box N-3910, Nassau,
Bahamas
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
3 Kairaba Avenue, 3rd Floor Centenary, Serekunda West, Kanifing Municipality, Gambia
BP Exploration (Greenland) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (Madagascar) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (Morocco) Limited
BP Exploration (Namibia) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (Nigeria Finance) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (Nigeria) Limited
BP Exploration (Psi) Limited
1, Oyinka Abayomi Drive, Ikoyi, Lagos, Nigeria
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (Shafag-Asiman) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (Shah Deniz) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (South Atlantic) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration (STP) Limited
BP Exploration (Xazar) Pte. Ltd.
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore
BP Exploration Angola (Kwanza Benguela) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Argentina Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Beta Limited
BP Exploration China Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Company (Middle East) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Company Limited
BP Exploration Indonesia Limited
BP Exploration Libya Limited
BP Exploration Mexico Limited
BP Exploration Mexico, S.A. De C.V.c
BP Exploration North Africa Limited
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F., Mexico
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Operating Company Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Orinoco Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Personnel Company Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Exploration Peru Limited
BP Express Shopping Limited
BP Finance Australia Pty Ltd
BP Finance p.l.c.
BP Foundation Incorporatedb
BP France
BP Fuels & Lubricants AS
BP Fuels Deutschland GmbH
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Tjuvholmen allé, Oslo, 0252, Norway
Wittener Straße 45, 44789 Bochum, Germany
BP Gas & Power Investments Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Gas Europe, S.A.U.
BP Gas Marketing Limited
BP Gas Supply (Angola) LLCb
BP Ghana Limited
BP Global Investments Limitedi
BP Global Investments Salalah & Co LLC
BP Global West Africa Limited
BP GOM Logistics LLCb
BP Greece Limited
BP Guangdong Limited (90.00%)b
Avenida de la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid,
Spain
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
PwC Tower, A4 Rangoon Lane, Cantonments City, PMB CT 42 Cantonments, Accra, Ghana
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
PO Box 2309, Salalah, 211, Oman
Heritage Place, 13th Floor, 21 Lugard Avenue, Ikoyi, Lagos, Nigeria
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
No 833, South Guang Zhou Avenue, Haizhu District, Guangzhou Province , China
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
278
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
BP High Density Polyethylene - France
BP Holdings (Thailand) Limited (81.18%)p
BP Holdings B.V.
BP Holdings Canada Limitedi
BP Holdings Central Europe B.V.
BP Holdings International B.V.
BP Holdings North America Limitedi
BP Hong Kong Limited
BP India Private Limited (88.65%)
BP Indonesia Investment Limited
BP International Limitedi
BP International Services Company
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Überseeallee 1, 20457 , Hamburg, Federal Republic of Germany, Germany
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Unit 25-150, 25/f, Two Harbour Square, 180 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong
Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400093, India
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
BP Investment Management Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Investments Asia Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Iran Limited
BP Iraq N.V.
BP Italia SpA
BP Japan K.K.
BP Korea Limited
BP Kuwait Limited
BP Latin America LLCb
BP Latin America Upstream Services Inc.
BP LNG Shipping Limited
BP Lubricants KK (64.84%)
BP Lubricants USA Inc.
BP Luxembourg S.A.
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Langerbruggekaai 18, 9000 Gent, Belgium
Via Verona 12, Cornaredo, 20010, Milan, Italy
15th Fl. Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan
19th Floor, 302, Teheran-ro, Gangnam-gu, Seoul, Korea, Republic of
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Washington House, 4th Floor, 16 Church Street, Hamilton HM 11 , Bermuda
East Tower 20F, Gate City Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Aire de Capellen, L-8309 Capellen, Luxembourg
BP Malaysia Holdings Sdn. Bhd. (70.00%)
Level 9, Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur,
Malaysia
BP Management International B.V.
BP Management Netherlands B.V.
BP Marine Limited
BP Mariner Holding Company LLCb
BP Maritime Services (Singapore) Pte. Limited
BP Marketing Egypt LLC
BP Mauritania Investments Limited
BP Mauritius Limited (in liquidation)
BP Middle East Enterprises Corporation
BP Middle East Limitedi
BP Middle East LLC
BP Midstream Partners GP LLCb
BP Midstream Partners Holdings LLCb
BP Midstream Partners LP (54.37%)q
BP Midwest Product Pipelines Holdings LLCb
BP Mocambique Limitada
BP Mocambique Limited
BP Muturi Holdings B.V.
BP Nederland Holdings BV
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore
Plot 28 , North 90 Road , Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
5th Floor, Ebene Esplanade, 24 Cybercity, Ebene, Mauritius
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
P.O.Box 1699, Dubai, 1699, United Arab Emirates
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Society and Geography Avenue, Plot No. 269 , Third floor, Maputo, Mozambique
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
BP Netherlands Upstream B.V.
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
BP New Ventures Middle East Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP New Zealand Holdings Limited
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
BP New Zealand Share Scheme Limited
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
BP Nutrition Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Offshore Gathering Systems Inc.
BP Offshore Pipelines Company LLCb
BP Offshore Response Company LLCb
BP Oil (Thailand) Limited (90.40%)r
BP Oil Australia Pty Ltd
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
BP Oil Espana, S.A. Unipersonal
Polígono Industrial "El Serrallo", s/n 12100 Grao de Castellón, Castellón de la Plana, Spain
BP Oil Hellenic S.A.
26A Apostolopoulou, Halandri, Athens, Attica, 152 31, Greece
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
279
14. Related undertakings of the group – continued
BP Oil International Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Oil Kent Refinery Limited (in liquidation)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Oil Llandarcy Refinery Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Oil Logistics UK Limited
BP Oil New Zealand Limited
BP Oil Pipeline Company
BP Oil Senegal S.A.
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Route de Ouakam x Corniche Ouest, Immeuble Alphadio Barry, Dakar, Senegal
BP Oil Shipping Company, USA
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Oil UK Limited
BP Oil Venezuela Limited
BP Oil Vietnam Limited
BP Oil Yemen Limited
BP Olex Fanal Mineralol GmbH
BP One Pipeline Company LLCb
BP Pacific Investments Ltd
BP Pakistan (Badin) Inc.
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Pakistan Exploration and Production, Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Pension Escrow Limited
BP Pension Trustees Limitedi
BP Pensions (Overseas) Limitedj
BP Pensions Limitedi
BP Petrochemicals India Investments Limited
BP Petroleo y Gas, S.A.
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Albert House, South Esplanade, St. Peter Port, GY1 1AW, Guernsey
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Francisco de Miranda, con primera avenida de Los Palos , Grandes, Edif Cavendes, piso 9, ofi 903, Los
Palos Grandes, Chacao / Caracas, Caracas / Miranda, 1060, Venezuela, Bolivarian Republic of
BP Petrolleri Anonim Sirketi
BP Pipelines (Alaska) Inc.
BP Pipelines (BTC) Limited
Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Pipelines (North America) Inc.
45 Memorial Circle, Augusta ME 04330, United States
BP Pipelines (SCP) Limited
BP Pipelines (TANAP) Limited
BP Pipelines TAP Limited
BP Polska Services Sp. z o.o.
BP Portugal -Comercio de Combustiveis e Lubrificantes
SA
BP Poseidon Limited
BP Products North America Inc.
BP Properties Limitedi
BP Raffinaderij Rotterdam B.V.
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Ul. Jasnogórska 1, 31-358 Kraków, Malopolskie, Poland
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
2405 York Road, Ste 201, Lutherville Timonium MD 21093-2264, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
BP Refinery (Kwinana) Proprietary Limited
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
BP Regional Australasia Holdings Pty Ltd
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
BP Retail Properties Limited
BP River Rouge Pipeline Company LLC (54.37%)f
BP Russian Investments Limited
BP Russian Ventures Limited
BP SC Holdings LLCb
BP Scale Up Factory Limited
BP Senegal Investments Limited
BP Services International Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Servicios de Combustibles S.A. de C.V.
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
BP Servicios territoriales, S.A. de C.V.
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
BP Shafag-Asiman Limited
BP Shipping Limited
BP Singapore Pte. Limited
BP Solar Espana, S.A. Unipersonalc
BP Solar International Inc.
BP Solar Pty Ltd
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore
Avenida de la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid,
Spain
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
BP South America Holdings Ltd
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Southern Africa Proprietary Limited (75.00%)
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
BP Southern Cone Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
280
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
BP Subsea Well Response (Brazil) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Subsea Well Response Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Taiwan Marketing Limited
BP Technology Ventures Inc.
7FNo. 71Sec. 3Min Sheng East Road, Taipei, Taiwan
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Technology Ventures Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP Train 2/3 Holding SRL
BP Trinidad and Tobago LLC (70.00%)b
BP Trinidad Processing Limited
BP Turkey Refining Limitedi
BP Two Pipeline Company LLC (54.37%)f
BP UK Fatima Limited
BP UK Retained Holdings Limited
BP Venezuela Investments B.V.
BP West Aru I Limited
BP West Aru II Limited
BP West Papua I Limited
BP West Papua III Limited
BP Wind Energy Beacon Holding LLCb
BP Wind Energy Empire Holding LLCb
BP Wind Energy North America Inc.
The Financial Services, Bishop's Court Hill, St. Michael, Barbados
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Wiriagar Ltd.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP Xiaoju New Energy (Shenzhen) Co., Ltd. (70.00%)
Room 201, Complex A, Qianwan Road 1, Qianhai Shenzhen-Hong Kong Cooperation Zone, Shenzhen City,
PRC
BP+Amoco International Limitedi
BP-AIOC Exploration (TISA) LLC (65.88%)b
BPNE International B.V.
BPRY Caribbean Ventures LLC (70.00%)b
BPX (Eagle Ford) Gathering LLC (75.00%)b
BPX (Karnes) Gathering LLCb
BPX (KCS Resources) LLCb
BPX (Permian) Gathering LLCb
BPX (WSF Operating) Inc.
BPX Energy Inc.
BPX Gathering Holdings LLCb
BPX Midstream LLCb
BPX Operating Company
BPX Production Company
BPX Properties (GP) LLCb
BPX Properties (LP) LLCb
BPX Properties (NA) LPf
Brian Jasper Nominees Pty Ltd
Britannic Energy Trading Limited
Britannic Investments Iraq Limited
Britannic Marketing Limited
Britannic Strategies Limited
Britannic Trading Limited
British Pipeline Agency Limited (50.00%)s
Britoil Limited
BTC Pipeline Holding Company Limited
Burmah Castrol Australia Pty Ltdt
Burmah Castrol Holdings Inc.
Burmah Castrol PLCi
Burmah Castrol South Africa (Pty) Limitedu
Burmah Chile SpA
BXL Plastics Limitedv
Cadman DBP Limited
Casitas Pipeline Company
Castrol (China) Limited
Castrol (Ireland) Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The Corporation Company, 1833 South Morgan Road, Oklahoma City OK 73128, United States
350 North St. Paul Street, Suite 2900, Dallas, Texas 75201, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
CT Corporation System, 1021 Main Street, Suite 1150, Houston, Texas 77002, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1999 Bryan St., STE 900, Dallas TX 75201, United States
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
Av. Américo Vespucio Sur No. 100, of. 1101, Las Condes, Santiago, Chile
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Unit 25-150, 25/f, Two Harbour Square, 180 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong
One Spencer Dock, North Wall Quay, Dublin 1, Ireland
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
281
14. Related undertakings of the group – continued
Castrol (Shanghai) Management Co., Ltdb
Castrol (Shenzhen) Company Limitedb
Castrol (Tianjin) Lubricants Co., Ltdb
Castrol (U.K.) Limited
Castrol Australia Pty. Limited
CASTROL Austria GmbH
Castrol B.V.
Castrol Belgium B.V.
Castrol BP Petco Limited Liability Company (65.00%)b
Castrol Brasil Ltda.
Floor 3, Building 5, 255 Guiqiao Road, Shanghai Pilot Free Trade Zone, China
No.1120 Mawan Road, Nanshan District, Shenzhen, China
South of NanGang Industrial Area, and East of Hai Gang Road, Tianjin Economic Development Area, Tianjin,
China
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Straße 6, Objekt 17, Industriezentrum NÖ-Süd,, 2355 Wr. Neudorf, Austria
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Langerbruggekaai 18, 9000 Gent, Belgium
9th Floor, 22-36 Nguyen Hue Street, 57-69F Dong Khoi Street, District 1, Ho Chi Minh City, Vietnam
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
Castrol Caribbean & Central America Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Castrol CEE spółka z ograniczoną odpowiedzialnością
Castrol Colombia Ltda.
ul. Grzybowska 62, 00-844, Warszawa, Poland
Calle 81, No 11 - 42, Oficina 901, Torre Sur, Bogota, Colombia
Castrol Del Peru S.A.
Av. Camino Real, 111 Torre B Oficina, 603 San Isidro, Lima, Peru
Castrol Egypt Lubricants S.A.E. (51.00%)
First floor of building located at Plot 28- the first Sector, City Center, New Cairo, Cairo, Egypt
Castrol Holdings Europe B.V.
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Castrol Holdings International Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Castrol India Limited (51.00%)
Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400093, India
Castrol Industrie und Service GmbH
Erkelenzer Straße 20, 41179 Mönchengladbach, Germany
Castrol KK (64.84%)
Castrol Limited
Castrol Lubricants RO S.R.L
Castrol Mexico, S.A. de C.V.c
Castrol Namibia (Pty) Limited
Castrol Nederland B.V.
Castrol Offshore Limited
East Tower 20F, Gate City Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan
Technology Centre, Whitchurch Hill, Pangbourne, Reading, RG8 7QR, United Kingdom
Bucharest, District 3, Boulevard Comeliu Coposu, no 6-8, Unirii View Building, Office 101, floor 1, Romania
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F., Mexico
24 Orban Street, Klein Windhoek, Windhoek, Namibia
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Castrol Pakistan (Private) Limited
D-67/1, Block # 4, Scheme # 5, Clifton, Karachi, Pakistan
Castrol Philippines, Inc.
Castrol Servicos Ltda.
Castrol Singapore PTE. Limited
Castrol Switzerland GmbH
Castrol Ukraine LLCb
Castrol Zimbabwe (Private) Limited
Centrel Pty Ltd
Charge Your Car Limitedc
Chargemaster (Europe) GmbH
Chargemaster Limited
Charging Solutions Limited
CH-Twenty, Inc.
Clarisse Holdings Pty Ltd
32/F LKG Tower, Ayala Avenue, Makati City, 6801, Philippines
Avenida Tamboré, 448, Barueri, Sao Paulo, Brazil
7 Straits View #26-01, Marina-One East Tower, 018936, Singapore
Baarerstrasse 139, 6300 Zug, Switzerland
2A Kostiantynivska Street, Kyiv, 04071, Ukraine
Barking Road, Willowvale, Harare, Zimbabwe
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Breckland, Linford Wood, Milton Keynes, MK146GY, United Kingdom
Wittener Straße 45, 44789 Bochum, Germany
Breckland, Linford Wood, Milton Keynes, MK146GY, United Kingdom
55 Baker Street, London, W1U 7EU, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Coastwise Trading Company, Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Consolidada de Energia y Lubricantes, (CENERLUB) C.A.
Avenida Eugenio Mendoza / San Felipe Edificio Centro Letonia, Torre Ing-Bank, Piso 12, Oficina 124-B, La
Castellana, Caracas, 1060, Venezuela, Bolivarian Republic of
Coro Trading NZ Limited
Cuyama Pipeline Company
Dermody Petroleum Pty. Ltd.
DHC Solvent Chemie GmbH
Dome Beaufort Petroleum Limited
Dome Wallis (1980) Limited Partnership (92.50%)f
Dradnats, Inc.
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Timmerhellstsr. 28, 45478, Mülheim/Ruhr, Germany
240 - 4th Avenue SW, Calgary AB T2P 4H4, Canada
240 - 4th Avenue SW, Calgary AB T2P 4H4, Canada
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
ECM Markets SA (Pty) Ltd (75.00%)
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
Elektromotive Limited
Breckland, Linford Wood, Milton Keynes, MK146GY, United Kingdom
Elite Customer Solutions Pty Ltd
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Elm Holdings Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Energy Global Investments (USA) Inc.
Enstar LLCb
Estonian Aviation Fuelling Services (50.00%)
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Harju maakond, Lasnamäe linnaosa, Väike-Sõjamäe tn 12a, Tallinn, 11415, Estonia
Europa Oil NZ Limited
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Exmoor Nominee Limited (51.00%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
282
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
Exmoor Properties GP Limited (51.00%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Exmoor Properties PF LP (51.00%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Exomet, Inc.
4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States
Expandite Contract Services Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Exploration (Luderitz Basin) Limited
Finite Carbon Corporation (80.50%)
Finite Resources, Inc. (80.50%)
Flat Ridge 2 Holdings LLCb
Flat Ridge Wind Energy, LLCb
Foseco Holding International B.V.
Foseco Holding, Inc.
Foseco, Inc.
Fosroc Expandite Limited
Fotech Group Limiteda
Fotech Solutions (Canada) Ltd.
Fotech USA, LLC
Fowler I Holdings LLCb
Fowler Ridge Holdings LLCb
Fowler Ridge I Land Investments LLCb
Fowler Ridge II Holdings LLCb
Fowler Ridge III Wind Farm LLCb
Fowler Ridge Wind Farm LLCb
FreeBees B.V.
Fuelplane- Sociedade Abastecedora De Aeronaves,
Unipessoal, Lda
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
435 Devon Park Drive, Suite 700, Wayne, Pennsylvania, 19087, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
112 SW 7th Street, Suite 3C, Topeka, Kansas, 66603
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
240-Fourth Avenue SW, Calgary AB T2P 4H4 Canada
1999 Bryan St., STE 900, Dallas TX 75201, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
FWK (2017) Limited (In Liquidation)
55 Baker Street, London, W1U 7EU, United Kingdom
FWK Holdings (2017) Ltd (In Liquidation)
55 Baker Street, London, W1U 7EU, United Kingdom
Gardena Holdings Inc.
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Gelsenkirchen Raffinerie Netz GmbH
Alexander-von-Humboldt-Straße 1, Gelsenkirchen, 45896, Germany
GOAM 1 C.I S. A .S
Calle 80 No.11-42 Oficina 901, Bogota, 110111, Colombia
Grampian Aviation Fuelling Services Limited (In
Liquidation)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Guangdong Investments Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Hangzhou BP Xiaoju New Energy Co., Ltd. (70.00%)
Highlands Ethanol, LLCb
Horizon 38 Management Company Limited (53.50%)
Room 1536, Building 2, Taimei International Building, Qiantang New District, Hangzhou City, Zhejiang Province
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
10 Upper Berkeley Street, London, W1H 7PE, United Kingdom
IGI Resources, Inc.
921 S. Orchard St. Ste G, Boise ID 83705, United States
Insight Analytics Solutions Holdings Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Insight Analytics Solutions Limited
Insight Analytics Solutions USA, Inc
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
2108 55th Street, Suite 105, Boulder CO 80301, United States
International Bunker Supplies Pty Ltd
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Iraq Petroleum Company Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Jinhua BP Xiaoju New Energy Co., Ltd. (70.00%)
Floor 1, No. 6, Panlong East Road, Fotang Town, Yiwu City, Zhejiang Province, China
Jupiter Insurance Limited
Ken-Chas Reserve Company
Kenilworth Oil Company Limitedi
Latin Energy Argentina S.A.
Lebanese Aviation Technical Services S.A.L.
Limited Liability Company BP Toplivnaya Kompaniab
Limited liability company Setra Lubricantsb
Low Carbon Friends Limited
Lubricants UK Limited
Lytt Limited
Suite 1 North, First Floor, Albert House, South Esplanade, St Peter Port, GY1 1AJ, Guernsey
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Cordoba 315 Piso 8, Buenos Aires, 1054, Argentina
P O Box - 11 -5814c/o Coral Oil Building, 583Avenue de Gaulle, Raoucheh, Beirut, Lebanon
Novinskiy blvd.8, 17th floor, premises 11, 121099, Moscow, Russian Federation
2 Paveletskaya sq, Building1, 115054 Moscow, Russia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Manormaker (Nominee No. 1) Limited (99.90%)
11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom
Manormaker (Nominee No. 2) Limited (99.90%)
11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom
Manormaker GP Limited (99.90%)
11 Black Horse Lane, Ipswich, Suffolk, IP1 2EF, United Kingdom
Mardi Gras Transportation System Company LLC
(70.34%)b
Markoil, S.A. Unipersonal
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida de la Transición Española 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid,
Spain
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
283
14. Related undertakings of the group – continued
Masana Petroleum Solutions (Pty) Ltd (37.88%)
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
Mayaro Initiative for Private Enterprise Development
(70.00%)b
Mehoopany Holdings LLCb
Mes Tecnologia En Servicios Y Energia, S.A. De C.V.c
Mountain City Remediation, LLCb
Net Zero North Sea Storage Limited
5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F., Mexico
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Net Zero Teesside Power Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
No. 1 Riverside Quay Proprietary Limited
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Nordic Lubricants A/S
Nordic Lubricants AB
Orestads Boulevard 73, 2300, Kobenhavn S, Denmark
Hemvärnsgatan , 171 54, Solna, Sweden
North America Funding Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
OMD87, Inc.
111 Eighth Avenue, New York, New York, 10011
OnSight Analytics Solutions India Private Ltd.
Office No. 306, Regus Business Center , 3rd Floor, Abbusali St, Saligramam, Chennai, Tamil Nadu, 600093,
India
Onyx Insight Korea Co., Ltd.
OOO BP STLb
Orion Delaware Mountain Wind Farm LPb
Orion Energy Holdings, LLCb
Orion Energy L.L.C.b
Orion Post Land Investments, LLCb
Pacroy (Thailand) Co., Ltd. (39.50%)
504-ho, 213-3, Cheomdan-ro, Jeju-si, Jeju-do, Korea, Republic of
Novinskiy blvd.8, 18th floor, office 14, 121099, Moscow, Russian Federation
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand
Pearl River Delta Investments Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Phoenix Petroleum Services, Limited Liability Company
Royal Tulip Al Rasheed Hotel, Baghdad Tower, PO Box 8070, Baghdad, Iraq
PRODUITS METALLURGIE DOITTAU
Prospect International, C.A. (In liquidation)
PT Castrol Indonesia (68.30%)
PT Castrol Manufacturing Indonesia (68.30%)
PT Jasatama Petroindoc
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Avenida Eugenio Mendoza / San Felipe Edificio Centro Letonia, Torre Ing-Bank, Piso 12, Oficina 124-B, La
Castellana, Caracas, 1060, Venezuela, Bolivarian Republic of
Perkantoran Hijau Arkadia, Tower B 9th Floor, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520,
Indonesia
JL. Raya, Merak KM 117, DS Gerem, Gerem Grogol, Cilegon, Banten, Indonesia
Perkantoran Hijau Arkadia, Tower B 8th Floor, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520,
Indonesia
RAPI SA (62.51%)
1, Proteos & 51, Anapafseos str, 15235 Vrilissia, Attica, Greece
Remediation Management Services Company
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Richfield Oil Corporation
Rolling Thunder I Power Partners, LLCb
Ropemaker Deansgate Limited
Ropemaker Properties Limited
Ruhr Oel GmbH (ROG)
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Alexander-von-Humboldt-Straße 1, Gelsenkirchen, 45896, Germany
Rusdene GSS Limited (In Liquidation)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Saturn Insurance Inc.
400 Cornerstone Drive, Suite 240, Williston VT 05495, United States
Shanghai Quanzhi New Energy Co., Ltd. (70.00%)
No. 399 Dongfeng highway, Dongping Town, Chongming District, Shanghai City, (Dongping Economic
Development, China
Sherbino I Holdings LLCb
Sherbino Mesa I Land Investments LLCb
Sociedade de Promocao Imobiliaria Quinta do Loureiro, SA Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
Société de Gestion de Dépots d'Hydrocarbures - GDHb
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
SOFAST Limited (63.09%)w
South Texas Shale LLCb
Southern Ridge Pipeline Holding Company
Southern Ridge Pipeline LP LLCb
SRHP (99.99%)b
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa South Sathon, Bangkok 10120, Thailand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Standard Oil Company, Inc.
Stryde Inc.
251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Stryde International Limited
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Stryde Limited
Sunrise Oil Sands Partnership (50.00%)f
Suzhou BP Xiaoju New Energy Co., Ltd. (70.00%)
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada
Room 703, Building 32, No.258 Shengpu Road, Suzhou Industrial Park, China
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
284
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
Taradadis Pty. Ltd.
Telcom General Corporation (99.96%)d
Terre de Grace Partnership (75.00%)f
The Anaconda Company
The BP Share Plans Trustees Limitedi
The Burmah Oil Company (Pakistan Trading) Limited
The Standard Oil Company
TISA Education Complex LLC (65.88%)b
TJKK
Toledo Refinery Holding Company LLCb
Union Texas International Corporation
Vastar Pipeline, LLCb
Viceroy Investments Limited
Warrenville Development Limited Partnershipb
Water Way Trading and Petroleum Services LLC
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
818 West Seventh Street, 2nd Floor, Los Angeles, CA, 90017
1100, 635 - 8th Avenue SW, Calgary AB T2P 3M3, Canada
814 Thayer Avenue, Bismarck, ND, 58501-4018
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States
153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan
15th Fl. Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
33 North LaSalle Street, Chicago, Illinois 60602, United States
Khur Al-Zubair, pear No 1, Basra, Iraq
Welchem, Inc.
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
West Kimberley Fuels Pty Ltd
Westlake Houston Development, LLCb
Whiting Clean Energy, Inc.
Windpark Energy Nederland B.V.
Winwell Resources, L.L.C.b
Wiriagar Overseas Ltd
Level 17, 717 Bourke Street, Docklands VIC 3008, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States
Estera Corporate Services (BVI) Limited, Jayla Place, Wickhams Cay 1, PO Box 3190, Road Town, Tortola,
VG1110, Virgin Islands, British
Zhuhai BP Xiaoju New Energy Co., Ltd. (70.00%)
Room 105-72746 (Centralized office area), No.6 Baohua Road, Hengqin New District, Zhuhai City, China
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
285
14. Related undertakings of the group – continued
Related undertakings other than subsidiaries
A Flygbranslehantering AB (AFAB) (25.00%)
Box 135, 190 46 Arlanda, Sweden
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Aashman Power Limited (49.97%)
ABG Autobahn-Betriebe GmbH (32.58%)b
Abu Dhabi Marine Areas Limited (33.33%)h
Advanced Biocatalytics Corporation (24.50%)a
AEP I HoldCo LLC (24.30%)b
AGES International GmbH & Co. KG, Langenfeld (24.70%)f Berghausener Straße 96, 40764 Langenfeld, Germany
Berghausener Straße 96, 40764 Langenfeld, Germany
AGES Maut System GmbH & Co. KG, Langenfeld
(24.70%)f
Brucknerstraße 4, 1041 Wien, Austria
1 More London Place, London, SE1 2AF, United Kingdom
18010 Skypark Circle , #130 , Irvine CA 92614, United States
Harvard Business Services, Inc., 16192 Coastal Hwy, Lewes, Delaware, 19958, United States
Air BP Copec S.A. (51.00%)
Air BP Italia Spa (50.00%)
Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile
Via Sardegna 38, 00187, Roma, Italy
Air BP PBF del Peru S.A.C. (50.00%)
Avenida Ricardo Rivera Navarrete n.501 / room 1602, Lima, Peru, Peru
Air BP Petrobahia Ltda. (50.00%)
Av. Anita Garibaldi, n.252, 2o floor, Ala Sul, Federação, Salvador, Bahia, 40210-750, Brazil
Aircraft Fuel Supply B.V. (28.57%)
Aircraft Refuelling Company GmbH (33.33%)b
Aker BP ASA (30.00%)
Alyssum Group Ltd (26.23%)e
Ambarli Depolama Hizmetleri Limited Sirketi (50.00%)
Oude Vijfhuizerweg 6, 1118LV Luchthaven, Schiphol, Netherlands
Trabrennstraße 6-8 3, A-1020, Wien, Austria
Oksenoyveien 10, , 1366 Lysaker, Norway
522 Fulham Road, London, SW6 5NR, United Kingdom
Yakuplu Mahallesi Genc, Osman Caddesi, No.7 Beylikdüzü, Istanbul, Turkey
Ammenn GmbH (75.00%)
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
Apollo Geração de Energia Ltda. (49.97%)
Sitio Canto, número S/N, bairro / distrito Zona Rural, município Russas - CE, CEP 62900-000, Brazil
Aragonesa de Gestión de Energías Alternativas, SL
(49.97%)
ATAS Anadolu Tasfiyehanesi Anonim Sirketi (68.00%)x
Atlantic 1 Holdings LLC (34.00%)b
Atlantic 2/3 Holdings LLC (42.50%)b
Atlantic 4 Holdings LLC (37.78%)b
Atlantic LNG 2/3 Company of Trinidad and Tobago
Unlimited (42.50%)
Atlantic LNG 4 Company of Trinidad and Tobago Unlimited
(37.78%)
Calle Alcala numero 63, 28014, Madrid, Spain
Degirmen yolu cad. No:28 , Asia OfisPark K:3 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago
Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago
Atlantic LNG Company of Trinidad and Tobago (34.00%)
Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago
Australasian Lubricants Manufacturing Company Pty Ltd
(50.00%)h
Australian Terminal Operations Management Pty Ltd
(50.00%)
Auwahi Holdings, LLC (50.00%)b
Auwahi Wind Energy LLC (50.00%)b
Aviation Fuel Services Limited (25.00%)
Aviation Service (Iraq) Limited (40.00%)y
Axion Comercializacion De Combustibles Y Lubricantes
S.A. (50.00%)
Axion Energy Argentina S.A. (50.00%)
Axion Energy Holding S.L. (50.00%)b
Axion Energy Paraguay S.R.L. (50.00%)b
Axuy Energy Holdings S.R.L. (50.00%)b
Axuy Energy Investments S.R.L. (50.00%)b
Azerbaijan Gas Supply Company Limited (23.06%)h
Building 1, 747 Lytton Road, Murarrie QLD 4172, Australia
Level 3, Unit 3, 22 Albert Road, South Melbourne VIC 3205, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Calshot Way Central Area, Heathrow Airport, Hounslow, Middlesex, TW6 1PY, United Kingdom
Mw1 Building 557 Shoreham Road, Heathrow Airport, London,TW6 3RT, United Kingdom
Luis A de Herrera 1248, Torre II, Piso 22 (Edificio World Trade Center), Montevideo, Uruguay
Carlos María Della Paolera 265, Piso 22, Ciudad Autónoma de Buenos Aires, Argentina
Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108 Alcobendas,
MADRID, SPAIN
Av. España 1369 esquina San Rafael, Asunción, Paraguay
Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay
Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
Azerbaijan International Operating Company (30.37%)z
Baplor S.A. (50.00%)
190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands
Colonia 810, Oficina 403, Montevideo, Uruguay
Barranca Sur Minera S.A. (50.00%)
Beer Energien GmbH & Co. KG (50.00%)f
Beer GmbH (50.00%)
Belenos s.r.l. (32.48%)
Bellflower Solar 1, LLC (49.97%)b
Belmont Technology Inc. (26.10%)
Bighorn Solar 1, LLC (49.97%)b
Bighorn Solar Class B, LLC (49.97%)b
Bighorn Solar Construction, LLC (49.97%)b
Calle 14, No 781, Piso 2, Oficina 3, Ciudad de La Plata, Provincia de Buenos Aires, Argentina
Saganer Straße 31, 90475 Nürnberg, Germany
Saganer Straße 31, 90475 Nürnberg, Germany
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
286
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
Bighorn Solar Holdings 1, LLC (49.97%)b
Bighorn Solar Holdings 2, LLC (49.97%)b
Bighorn Solar Holdings, LLC (49.97%)b
Billund Refuelling I/S (50.00%)
Birch Solar 1, LLC (49.97%)b
Blackbear Alabama Solar 1, LLC (49.97%)b
Blackbear Alabama Solar Land Holdings, LLC (49.97%)b
Blendcor (Pty) Limited (37.50%)y
Blue Marble Holdings Limited (23.58%)⍺
Blue Ocean Seismic Services Limited (23.33%)a
Bodmin Solar Limited (49.97%)
BP AOC Pumpstation Maatschap (50.00%)f
BP Bioenergia Campina Verde Ltda. (48.27%)
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
GA Centervej 1, DK-7190, Billund, Denmark
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
135 Honshu Road, Islandview, Durban, 4052, South Africa
Northgate House, 2nd Floor, Upper Borough Walls, Bath, BA1 1RG, United Kingdom
12-14 Carlton Place, Southampton, SO15 2EA, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Rua Principal, Fazenda Recanto, Zona Rural, Caixa Postal 01, Ituiutaba, Minas Gerais, 38.300-898, Brazil
BP Bioenergia Ituiutaba Ltda. (48.27%)
Fazenda Recanto, Zona Rural, CEP 38.300-898, Ituiutaba, Minas Gerais, Brazil
BP Bioenergia Itumbiara S.A. (48.27%)
Estrada Municipal Itumbiara / Chacoeira Dourada, Fazenda Jandaia, Gleba B, Itumbiara, Goiás, 75516-126,
Brazil
BP Bioenergia Tropical S.A. (48.27%)
Rodovia GO 410, km 51 à esquerda, Fazenda Canadá, s/n, Zona Rural, Edéia, Goiás, 75940-000, Brazil
BP Bunge Bioenergia S.A. (48.27%)
Avenida das Nações Unidas, nº 12.399, 4º andar, Brooklin Paulista, São Paulo, CEP 04578-000, Brazil
BP Dhofar LLC (49.00%)
BP Esso AOC Maatschap (22.80%)f
BP Esso Pipeline Maatschap (50.00%)f
BP Guangzhou Development Oil Product Co., Ltd
(40.00%)b
BP Petro China Jiangmen Fuels Co., Ltd. (49.00%)b
BP PetroChina Petroleum Co., Ltd (49.00%)b
BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%)b
BP Sinopec Marine Fuels Pte. Ltd. (50.00%)
BP SPG Energy Trading Co., Ltd. (49.00%)
BP West Africa Supply Limited (50.00%)
BP-Husky Refining LLC (50.00%)b
BP-Japan Oil Development Company Limited (50.00%)h
Braendstoflageret Kobenhavns Lufthavn I/S (20.83%)f
Brechin Castle Solar Limited (49.97%)
Briar Creek Solar 1, LLC (49.97%)b
BTC International Investment Co. (30.10%)β
Burnthouse Solar Limited (49.97%)
Caesar Oil Pipeline Company, LLC (39.39%)b
Cairns Airport Refuelling Service Pty Ltd (33.33%)
Cantera K-3 Limited Partnership (39.00%)f
Canton Renewables, LLC (50.00%)b
Castrol Cuba S.A. (50.00%)
Castrol DongFeng Lubricant Co., Ltd (50.00%)b
P.O.Box 20302/211, 20302, Oman
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Room X2072, 2/F, No.13 Longxue Road, Longxue Island, Nansha District, Guangzhou, Guangdong, 511450,
China
Room A, building B , 5th floor, no. 22 Gangkou road, Jiangmen, China
Room B1, 11th Floor, No.22 Gang Kou Yi Road, Peng Jiang District, Jiangmen, Guangdong Province, China
F12, Hua Zhe Square Tower 1, Hang Zhou City, Zhe Jiang Province, China
112 Robinson Road, #05-01, Robinson 112, 068902, Singapore
Room 8309, Floor 3, Yufanghailian Office Building, No. 1 Indian Ocean Road, West Coast Comprehensive
Bonded Area, Qingdao Division of the PRC (Shandong) , China
Number 1, Rehoboth Place, Dade Street, North Labone Estates, Accra, Accra Metropolitan, Greater Accra, P.
O. BOX CT3278, Ghana
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Københavns, Lufthavn, 2770 Kastrup, Denmark
48-50 Sackville Street, Port of Spain, Trinidad and Tobago
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Company Matters Pty Ltd, Level 12, 680 George Street, Sydney NSW 2000, Australia
6400 Shafer Ct., Suite 400, Rosemont IL 60018-4927, United States
30600 Telegraph Road, Suite 2345, Bingham Farms MI 48025, United States
Calle 6 No 319, esq 5ta. Ave., Miramar, Playa, La Habana, Cuba
C1/C2-1, C1/C2-2, 1-6F, No. C1/C2 building, No.107 Huazhong Electronics Industry Park, Fangcao 2 Road,
Wuhan Economic and Technological Development Zone, Wuhan, Hubei Province, China
Cedar Creek II Holdings LLC (50.00%)b
Cedar Creek II, LLC (50.00%)b
Cefari RNG OKC, LLC (50.00%)b
Cekisan Depolama Hizmetleri Limited Sirketi (35.00%)
Central African Petroleum Refineries (Pvt) Ltd (20.75%)
CERF Shelby, LLC (50.00%)b
Chicap Pipe Line Company (56.17%)
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1560 Broadway, Suite 2090, Denver, Colorado, 80202
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Liman Mah. 60 Sk., Çekisan-İdari Bina sit. No:25 A/1, Konyaaltı, Antalya, Turkey
Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe
800 S. Gay Street, Suite 2021, Knoxville TN 37929, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
China Aviation Oil (Singapore) Corporation Ltd (20.03%)
8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore
Chittering Solar Limited (49.97%)
Clean Eagle RNG, LLC (50.00%)b
Cleopatra Gas Gathering Company, LLC (37.28%)b
CNAF Air BP General Aviation Fuel Company Limited
(49.00%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
11/F, Building No.2, No. 32 Lingang Road Section One, Xihang Port Street, Shuangliu District, Chengdu,
Sichuan Province, China
Coastal Oil Logistics Limited (25.00%)
10th Floor, The Bayleys Building, Cnr Brandon St and Lambton Quay, Wellington, 6011, New Zealand
Compatibleglobe, Lda (49.97%)
Rua Sousa Martins, no 10, 1050 218, Lisboa, Portugal
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
287
14. Related undertakings of the group – continued
Concessionaria Stalvedro SA (50.00%)
Continental Divide Solar 1, LLC (49.97%)b
Continental Divide Solar II, LLC (49.97%)b
Continental Divide Solar Land Holdings, LLC (49.97%)b
Cottontail Solar 1, LLC (49.97%)b
Cottontail Solar 2, LLC (49.97%)b
Cottontail Solar 3, LLC (49.97%)b
Cottontail Solar 4, LLC (49.97%)b
Cottontail Solar 5, LLC (49.97%)b
Cottontail Solar 6, LLC (49.97%)b
Cottontail Solar 7, LLC (49.97%)b
CSG Convenience Service GmbH (24.80%)
Danish Refuelling Services I/S (50.00%)f
Danish Tankage Services I/S (50.00%)f
Dapsun - Investimentos e Consultoria, LDA. (24.99%)
San Gottardo Sud, 6780, Airolo, Switzerland
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Wittener Straße 45, 44789 Bochum, Germany
Kastrup Lufthavn, 2770 Kastrup, Denmark
Kastrup Lufthavn, 2770 Kastrup, Denmark
Rua Júlio Dinis, n.º 247, 6.º, E-1, Edifício Mota Galiza, Parish of Lordelo do Ouro and Massarelos, 4050-324,
Porto, Portugal
Dinarel S.A. (20.00%)
La Cumparsita 1373, piso 4°, Montevideo, Uruguay
Donoma Power Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
DOPARK GmbH (25.00%)
Dusseldorf Fuelling Services GbR (33.00%)f
El Temsah Petroleum Company
"PETROTEMSAH" (25.00%)
Elk Hill Solar 1, LLC (49.97%)b
Elk Hill Solar 2, LLC (49.97%)b
Elk Hill Solar 2 Holdings, LLC (49.97%)b
Elm Branch Solar 1, LLC (49.97%)b
EMDAD Aviation Fuel Storage FZCO (33.33%)
Westfalendamm 166, 44141 Dortmund, Germany
Sportallee 6, 22335 Hamburg, Germany
5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
P.O.Box 261781, Dubai, United Arab Emirates
Emoil Storage Company FZCO (20.00%)
Plot No. B003R04, Box No. 9400, Dubai, United Arab Emirates, Dubai, United Arab Emirates
EMSEP S.A. de C.V. (50.00%)
Endymion Oil Pipeline Company, LLC (45.72%)b
Energías Renovables de Ixion, SL (49.97%)
Energy Emerging Investments, LLC (50.00%)b
Entrepot petrolier de Chambery (32.00%)
Av. Paseo de la Reforma 505 piso 32, Colonia Cuauhtémoc, Delegación Cuauhtémoc (06500), CDMX, Mexico
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Calle Alcala numero 63, 28014, Madrid, Spain
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
562 Avenue du Parc de l'Ile, 92000, NANTERRE, France
Entrepôt Pétrolier de Puget sur Argens - EPPA (58.25%)
Campus Saint Christophe, Bâtiment Galilée 3, 10 Avenue de l'Entreprise, 95863, Cergy Saint Christophe,
Cergy Pontoise, France
Erdol-Lagergesellschaft m.b.H. (23.00%)b
Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG
(33.33%)f
Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH
(33.33%)
Eversource Capital Private Limited (24.99%)
Radlpaßstraße 6, 8502 Lannach, Austria
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
One Indiabulls Center, 16th Floor, Tower 2A, Senapati Bapat Marg, Mumbai City, Maharashtra, Mumbai,
400013, India
EverSource Management Holdings (24.99%)
3rd Floor, Standard Chartered Tower, Bank Street, 19 Cybercity, Ebene, 72201, Mauritius
Ffos Las Solar Developments Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Field Services Enterprise S.A. (50.00%)
Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina
Fip Verwaltungs GmbH (50.00%)
Flat Ridge 2 Wind Energy LLC (50.00%)b
Flat Ridge 2 Wind Holdings LLC (50.00%)b
Flughafen Hannover Pipeline Verwaltungsgesellschaft
mbH (50.00%)
Flughafen Hannover Pipelinegesellschaft mbH & Co. KG
(50.00%)f
Fly Victor Ltd (26.23%)
Flytanking AS (50.00%)
Foreseer Ltd (25.00%)
Fowler II Holdings LLC (50.00%)b
Fowler Ridge II Wind Farm LLC (50.00%)b
Free Power for Schools 13 Limited (49.97%)
Rheinstraße 36, 49090 Osnabrück, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
60 Sloane Avenue, London, SW3 3XB, United Kingdom
Postboks 36, Stjordal, NO-7501, Norway
121A Thoday Street, Cambridge , Cambridgeshire, CB1 3AT , United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Free Power for Schools 14 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Free Power for Schools 15 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Free Power for Schools 17 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
288
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
Free Power for Schools 19 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Free Power for Schools 4 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Free Power for Schools 5 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Free Power for Schools 6 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Free Power for Schools 7 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Freetricity Central June Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Freetricity Commercial June Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
FreeWire Technologies, Inc. (28.18%)
Fresh-Serve Bakeries LLC (44.27%)b
Fuelling Aviation Service - FAS (50.00%)b
Fuerzas Energéticas del Sur de Europa IV, SL (49.97%)
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Corporation Service Company, 421 West Main Street, Frankfort KY 40601, United States
3 Rue des Vignes, Aéroport Roissy Charles de Gaulle, 93290, TREMBLAY EN FRANCE, France
Calle Alcala numero 63, 28014, Madrid, Spain
Fuerzas Energéticas del Sur de Europa XIX, SL (49.97%)
Calle Alcala numero 63, 28014, Madrid, Spain
Fuerzas Energéticas del Sur de Europa, S.L. (49.97%)
Calle Alcala numero 63, 28014, Madrid, Spain
Fundación para la Eficiencia Energética de la Comunidad
Valenciana (33.33%)b
Calle Lituania nº 10, Castellón de la Plana, Spain
Gardermeon Fuelling Services AS (33.33%)
Postboks 133, Gardermoen, NO-2061, Norway
Gas Natural Acu Comercializadora de Energia Ltda.
(50.00%)
Rua do Russel 804, 5th floor, Gloria, Rio de Janeiro, Brazil
Gas Natural Acu S.A. (30.00%)
Praia do Flamengo 66, 13th and 14th floors, Block A, Flamengo, Rio de Janeiro, Brazil
Gas Natural Infraestrutura S.A. (27.96%)
Rua do Russel 804, 5th floor, Gloria, Rio de Janeiro, Brazil
Gemalsur S.A. (50.00%)
Georgian Pipeline Company (30.37%)z
Gezamenlijke Tankdienst Schiphol B.V. (50.00%)
GISSCO S.A. (50.00%)
Glade CD Solar Holdings, LLC (49.97%)b
Glade Solar Class B, LLC (49.97%)b
Glade Solar Construction Holdings, LLC (49.97%)b
Glade Solar Construction, LLC (49.97%)b
Glade Solar Holdings 1, LLC (49.97%)b
Glade Solar Holdings 2, LLC (49.97%)b
Glade Solar Holdings, LLC (24.99%)b
Glade Solar Land Holdings, LLC (49.97%)b
Gnowee Power Limited (49.97%)
Goshen Phase II LLC (50.00%)b
Gothenburgh Fuelling Company AB (GFC) (33.33%)
Great Ropemaker Partnership (G.P.) Limited (50.00%)y
Great Ropemaker Property (Nominee 1) Limited (50.00%)
Colonia 810, Oficina 403, Montevideo, Uruguay
190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands
Anchoragelaan 6, 1118LD Luchthaven Schiphol, Netherlands
2,Vouliagmenis Ave & Papaflessa, 16777 Elliniko, Athens, Attika, Greece
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Corporation Service Company, 251 Little Falls Drive, Wilmington, DE 19808
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Box 2154, 438 14, LANDVETTER, Sweden
33 Cavendish Square, London, W1G 0PW, United Kingdom
33 Cavendish Square, London, W1G 0PW, United Kingdom
Great Ropemaker Property (Nominee 2) Limited (50.00%)
33 Cavendish Square, London, W1G 0PW, United Kingdom
Great Ropemaker Property Limited (50.00%)
33 Cavendish Square, London, W1G 0PW, United Kingdom
Green Growth Feeder Fund Pte. Ltd (24.99%)
163 Penang Road, #08-01, Winsland House II, 238463, Singapore
Groupement Pétrolier de Saint Pierre des Corps - GPSPC
(20.00%)b
Guangdong Dapeng LNG Company Limited (30.00%)b
GVÖ Gebinde-Verwertungsgesellschaft der
Mineralölwirtschaft mbH (21.00%)
H7 Energy Limited (49.97%)
Hamburg Tank Service (HTS) GbR (33.00%)f
Happy Solar 1, LLC (49.97%)b
Hebei Dongming Yinglun Petroleum Co., Ltd. (49.00%)b
Heinrich Fip GmbH & Co. KG (50.00%)f
Heliex Power Limited (32.40%)a
Henan Dongming Yinglun Petroleum Co., Ltd. (49.00%)b
HFS Hamburg Fuelling Services GbR (50.00%)f
Hiergeist Heizolhandel GmbH & Co. KG (50.00%)f
Hokchi Energy S.A. de C.V. (50.00%)
Hokchi Iberica S.L. (50.00%)
150 Avenue Yves Farge, 37700, SAINT PIERRE DES CORPS, France
10-11/FTime Finance Center, No.4001 Shennan Dadao, Futian Street, Futian District, Shenzhen, Guangdong
Province, China
Steindamm 55, 20099 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sportallee 6, 22335 Hamburg, Germany
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
South Side, Floor 10, Insurance Industrial Park, No. 672, Chengjiao Street,, Qiaoxi District, Shijiazhuang City,
Hebei Province, China
Rheinstraße 36, 49090 Osnabrück, Germany
Kelvin Building , Bramah Avenue , East Kilbride, Glasgow , Scotland, G75 0RD, United Kingdom
Room 124, Longhu Enterprise Service Center, Floor 1, Building No. 10, Courtyard No.1, Long Xing Jia Yuan,
No. 66, Longhu Outer Ring Road, Zhengdong New District, Zhenzhou City
Sportallee 6, 22335 Hamburg, Germany
Grubenweg 4, 83666 Waakirchen-Marienstein, Germany
Torre A, piso 4, oficina 402, Calzada Legaria 549, Colonia 10 de Abril, Delegación Miguel Hidalgo, Ciudad de
Mexico, C. P. 11250, Mexico
Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas (M-603), km 3.8, Alcobendas,
Madrid, Spain
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
289
14. Related undertakings of the group – continued
Howbery Solar Park Limited (49.97%)
Impact Solar 1, LLC (49.97%)b
Impact Solar Class B, LLC (49.97%)b
Impact Solar Construction, LLC (49.97%)b
Impact Solar Holdings 1, LLC (49.97%)b
Impact Solar Holdings 2, LLC (49.97%)b
Impact Solar Holdings, LLC (49.97%)b
Implantación de Fuentes Energéticas de Origen
Renovable, SL (49.97%)
In Salah Gas Limited (25.50%)y
In Salah Gas Services Limited (25.50%)y
India Gas Solutions Private Limited (50.00%)
Jamaica Aircraft Refuelling Services Limited (51.00%)h
Johnson Corner Solar I, LLC (24.99%)b
Kala Power Limited (49.97%)
Klaus Köhn GmbH (50.00%)
Köhn & Plambeck GmbH & Co. KG (50.00%)f
Kurt Ammenn GmbH & Co. KG (50.00%)f
LCA Aviation Fuelling Systems Limited (35.00%)
Lensky Nefteprovod Limited Liability Company (20.00%)
LFS Langenhagen Fuelling Services GbR (50.00%)f
Lightning Systems, Inc. (35.30%)a
Lightsource Asset Holdings (Australia) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Calle Alcala numero 63, 28014, Madrid, Spain
IFC 5, St Helier, Jersey, JE1 1ST, Jersey
IFC 5, St Helier, Jersey, JE1 1ST, Jersey
Unit Nos.71 & 737th Floor, Maker Maxity, 2nd North Avenue, Bandra - Kurla Complex, Bandra (East), Mumbai
400 051, Maharashtra, India
PCJ Building36 Trafalgar Road, Kingston 10, Jamaica
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
An der Braker Bahn 22, 26122 Oldenburg, Germany
An der Braker Bahn 22, 26122 Oldenburg, Germany
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
90 Archiepiskopou str, Dromolaxia – Meneou, 7020 Larnaca , Cyprus
Pervomayskaya str, 32a, Republic of Saha (Yakytya), 678144, city of Lensk, Lenskiy region, Russian Federation
Sportallee 6, 22335 Hamburg, Germany
160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings (Europe) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings (Spain) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings (UK) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings (USA) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings (Vendimia I) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings (Vendimia II) Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Holdings 3 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Asset Management Australia Pty Ltd
(49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Lightsource Asset Management Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Australia FinCo Holdings Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Australia SPV 1 Pty Limited (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Lightsource Australia SPV 2 Pty Limited (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Lightsource Australia SPV 3 Pty Limited (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Lightsource Australia SPV 4 Pty Limited (49.97%)
Lightsource Beacon 2, LLC (49.97%)b
Lightsource Beacon Holdings, LLC (49.97%)b
Lightsource Beacon, LLC (49.97%)b
Lightsource Bodegas 2 Limited (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Bodegas 3 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Bodegas 4 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Bodegas Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Bom Lugar IV Geração de Energia Ltda
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000,
Brazil
Lightsource Bom Lugar IX Geração de Energia Ltda.
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000,
Brazil
Lightsource Bom Lugar V Geração de Energia Ltda.
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000,
Brazil
Lightsource Bom Lugar VI Geração de Energia Ltda.
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000,
Brazil
Lightsource Bom Lugar VII Geração de Energia Ltda.
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000,
Brazil
Lightsource Bom Lugar VIII Geração de Energia Ltda.
(49.97%)
Fazenda Terra Nova, located at Rod. Padre Cicero (CE 153), S/N, KM 58, Lima Campos, Ico, Ceara, 63.435-000,
Brazil
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
290
bp Annual Report and Form 20-F 2020
14. Related undertakings of the group – continued
Lightsource BP Hassan Allam Developments for
Renewable Energy S.A.E (24.99%)
14 Kamal El Tawil ST, Zamalek, Cairo, Egypt
Lightsource BP Hassan Allam Holdings B.V. (24.99%)
Jan van Goyenkade 8, 1075HP, Amsterdam, Netherlands
Lightsource BP Renewable Energy Investments Limited
(49.97%)γ
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Brasil Energia Renovável Ltda (49.97%)
Avenida Bernardino de Campos 98, 12th floor, room 38, suite A, Paraiso, Sao Paulo, 04004-040, Brazil
Lightsource Brasil Energia Renovável Particições S.A.
(49.97%)
Avenida Bernardino de Campos 98, 12th floor, room 38, suite A, Paraiso, Sao Paulo, 04004-040, Brazil
Financial statements
Lightsource Brazil Holdings 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Lightsource Brazil Holdings 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Commercial Rooftops (Buyback) Limited
(49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Commercial Rooftops Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Construction Management Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Development Services Australia Pty Ltd
(49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Lightsource Development Services Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Egypt Holdings Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Lightsource Elk Hill 2 Solar Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Elk Hill Solar 2 Holdings Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Europe Asset Management, SL (49.97%)
Calle Suero de Quinones, Numero 34-36, 28002, Madrid, Spain
Lightsource Finance 55 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Lightsource Finca 2 Limited (49.97%)
Lightsource Finca 3 Limited (49.97%)
Lightsource Finca Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Grace 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Grace 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Grace 3 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Greece SPV 1 Single Member S.A. (49.97%)
280 Kifissias Ave, 152 32 Halandri, Anthens, Greece
Lightsource Holdings 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Holdings 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Holdings 3 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Iberia Project Holdings Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Impact 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Impact 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource India Holdings (Mauritius) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource India Holdings Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource India Investments (UK) Limited (49.97%)
Lightsource India Limited (25.49%)h
Lightsource India Maharashtra 1 Holdings Limited
(49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource India Maharashtra 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Kingfisher Holdings Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Kingpin 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Kingpin 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Kingpin 3 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Labs 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Lightsource Labs Australia Pty Limited (49.97%)
C/- Baker McKenzie, Level 19, 181 William Street, Melbourne VIC 3000, Australia
Lightsource Labs Holdings Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Lightsource Labs Limited (49.97%)
Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland
Lightsource Largescale Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Manzanilla Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Midscale Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Milagres I Geração de Energia Ltda. (49.97%) Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Lightsource Milagres II Geração de Energia Ltda. (49.97%) Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Lightsource Milagres III Geração de Energia Ltda.
(49.97%)
Lightsource Milagres IV Geração de Energia Ltda.
(49.97%)
Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Lightsource Milagres V Geração de Energia Ltda. (49.97%) Sítio Cajueiro - Abaiara - left of BR 116, KM491, Caatinga Grande, Zona Rural, Abaiara, 63.240-000, Brazil
Lightsource Nala Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
291
14. Related undertakings of the group – continued
Lightsource Operations 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Operations 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Operations 3 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Operations Services Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Poland Holdings (UK) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Property 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Property 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Property Investment Holdings Ltd (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Property Investment Management (LPIM) LLP
(49.97%)f
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Property Investments 1 Ltd (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Pumbaa Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Radiate 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Radiate 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Raindrop Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy (Australia) Pty Ltd
(49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Lightsource Renewable Energy (India) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource Renewable Energy Asset Holdings 1, LLC
(49.97%)b
Lightsource Renewable Energy Asset Holdings, LLC
(49.97%)b
Lightsource Renewable Energy Asset Management
Holdings, LLC (49.97%)b
Lightsource Renewable Energy Asset Management, LLC
(49.97%)b
Lightsource Renewable Energy Australia Holdings Limited
(49.97%)
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy Cariñena S.L. (49.97%)
Calle Alcala numero 63, 28014, Madrid, Spain
Lightsource Renewable Energy Development, LLC
(49.97%)b
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
Lightsource Renewable Energy Garnacha, S.L. (49.97%)
Calle Alcala numero 63, 28014, Madrid, Spain
Lightsource Renewable Energy Greece Holdings (UK)
Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy Holdings Limited (49.97%) 7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy Iberia Holdings Limited
(49.97%)
Lightsource Renewable Energy India Assets Limited
(49.97%)
Lightsource Renewable Energy India Holdings Limited
(49.97%)
Lightsource Renewable Energy India Opco Private Limited
(49.97%)
Lightsource Renewable Energy India Projects Limited
(49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
815-816 International Trade Tower, Nehru Place, New Delhi 110019, Delhi, India
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy Ireland Limited (49.97%)
Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland
Lightsource Renewable Energy Italy Development s.r.l.
(49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy Finco s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy Holdings Limited
(49.97%)
Lightsource Renewable Energy Italy Holdings s.r.l.
(49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 1 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 10 s.r.l. (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 11 S.r.l (49.97%) Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 2 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 3 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 4 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 6 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 7 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Italy SPV 8 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
292
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
Lightsource Renewable Energy Italy SPV 9 s.r.l. (49.97%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Lightsource Renewable Energy Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy Management, LLC
(49.97%)b
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
Lightsource Renewable Energy Netherlands Development
B.V. (49.97%)
Prins Bernhardplein 200
1097JB, Amsterdam, Netherlands
Lightsource Renewable Energy Netherlands Holdings B.V.
(49.97%)
Prins Bernhardplein 200
1097JB, Amsterdam, Netherlands
Lightsource Renewable Energy Netherlands Holdings
Limited (49.97%)
Lightsource Renewable Energy Operations, LLC (49.97%)b Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
7th Floor
33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Renewable Energy Portugal (HoldCo), Lda
(49.97%)
Lightsource Renewable Energy Portugal Holdings Limited
(49.97%)
Lightsource Renewable Energy Services Holdings, LLC
(49.97%)b
Rua Sousa Martins, no 10, 1050 218, Lisboa, Portugal
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Lightsource Renewable Energy Services, Inc. (49.97%)
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Lightsource Renewable Energy Spain Development, SL
(49.97%)
Lightsource Renewable Energy Spain Holdings, SL
(49.97%)
Calle Alcala numero 63, 28014, Madrid, Spain
Calle Alcala numero 63, 28014, Madrid, Spain
Lightsource Renewable Energy Spain SPV 1, SL (49.97%) Calle Alcala numero 63, 28014, Madrid, Spain
Lightsource Renewable Energy Trading, LLC (49.97%)b
Lightsource Renewable Energy Trading, SL (49.97%)
Lightsource Renewable Energy US Assets, LLC (49.97%)b 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Lightsource Renewable Energy US, LLC (49.97%)b
Lightsource Renewable Global Development Limited
(49.97%)
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
C/Pradillo 5, Bajo Exterior Derecha, 28002, Madrid, Spain
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
Lightsource Renewable Services Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Lightsource Renewable UK Development Limited
(49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Residential NI Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource Residential Rooftops (Buyback) Limited
(49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Residential Rooftops (PPA) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Residential Rooftops Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Simba Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Singapore Renewables Holdings Private
Limited (49.97%)
Lightsource Singapore Renewables Private Limited
(49.97%)
8 Marina Boulevard, #05-02, Marina Bay Financial Centre, 018981, Singapore
8 Marina Boulevard, #05-02, Marina Bay Financial Centre, 018981, Singapore
Lightsource Spain O&M, SL (49.97%)
Calle Suero de Quinones, Numero 34-36, 28002, Madrid, Spain
Lightsource SPV 10 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 100 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 101 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 105 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 106 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 108 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 109 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 112 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 114 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 115 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 116 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 118 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 123 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 126 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 127 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 128 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 130 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 133 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
293
14. Related undertakings of the group – continued
Lightsource SPV 135 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 138 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 140 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 142 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 143 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 145 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 149 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 151 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 152 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 154 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 155 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 156 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 160 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 162 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 166 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 167 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 169 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 170 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 171 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 174 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 175 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 176 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 179 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 18 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 180 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 182 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 183 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 184 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 185 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 187 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 189 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 19 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 191 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 192 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 196 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 199 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 20 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 200 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 201 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 202 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 203 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 204 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 205 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 206 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 212 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 213 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 214 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 215 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 216 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 217 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 221 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 222 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 223 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 224 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 232 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 233 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 234 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 235 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 236 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
294
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
Lightsource SPV 239 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 242 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 243 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 244 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 245 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 246 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 247 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 248 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 249 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 25 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 251 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 252 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 253 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 254 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 258 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 259 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 26 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 261 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 262 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 263 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 264 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 265 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 266 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 267 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 268 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 269 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 270 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 271 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 272 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 273 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 274 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 275 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 276 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 277 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 278 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 279 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 280 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 281 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 282 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 283 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 284 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 285 (NI) Limited (49.97%)
Regus Business Centre, Cromac Square, Belfast, Northern Ireland, BT2 8LA, United Kingdom
Lightsource SPV 286 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource SPV 29 Limited (49.97%)
Lightsource SPV 32 Limited (49.97%)
Lightsource SPV 35 Limited (49.97%)
Lightsource SPV 39 Limited (49.97%)
Lightsource SPV 40 Limited (49.97%)
Lightsource SPV 41 Limited (49.97%)
Lightsource SPV 42 Limited (49.97%)
Lightsource SPV 44 Limited (49.97%)
Lightsource SPV 47 Limited (49.97%)
Lightsource SPV 49 Limited (49.97%)
Lightsource SPV 5 Limited (49.97%)
Lightsource SPV 50 Limited (49.97%)
Lightsource SPV 54 Limited (49.97%)
Lightsource SPV 56 Limited (49.97%)
Lightsource SPV 60 Limited (49.97%)
Lightsource SPV 69 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
295
14. Related undertakings of the group – continued
Lightsource SPV 73 Limited (49.97%)
Lightsource SPV 74 Limited (49.97%)
Lightsource SPV 75 Limited (49.97%)
Lightsource SPV 76 Limited (49.97%)
Lightsource SPV 78 Limited (49.97%)
Lightsource SPV 79 Limited (49.97%)
Lightsource SPV 8 Limited (49.97%)
Lightsource SPV 88 Limited (49.97%)
Lightsource SPV 91 Limited (49.97%)
Lightsource SPV 92 Limited (49.97%)
Lightsource SPV 98 Limited (49.97%)
Lightsource Timon Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Trading Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Trinidad Holdings (UK) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Viking 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Viking 2 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Xenium 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Lightsource Xenium 2 Limited (49.97%)
Limited Liability Company TYNGD (20.00%)b
Limited Liability Company Yermak Neftegaz (49.00%)b
LL Property Services 2 Limited (49.97%)
LL Property Services Limited (49.97%)
LLC "Kharampurneftegaz" (49.00%)b
Lora Solar Limited (49.97%)
Lotos - Air BP Polska Spółka z ograniczoną
odpowiedzialnością (50.00%)
LREHL Renewables India SPV 1 Private Limited (25.49%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation
Kosmodamianskaya nab, 52/3, 115035, Moscow, Russian Federation
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
629830 Yamalo-Nenetskiy Anatomy Region, city of Gubkinskiy, Russian Federation
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Grunwaldzka 472B, 80-309, Gdansk, Poland
815-816 International Trade Tower, Nehru Place, New Delhi, 110019, India
LS Australia FinCo 1 Pty Limited (49.97%)
C/- Baker McKenzie, Level 19, 181 William Street, Melbourne VIC 3000, Australia
LS Australia FinCo 2 Pty Limited (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
LS Australia HoldCo1 Pty Ltd (49.97%)
LSBP NE Development, LLC (49.97%)b
Maasvlakte Europoort Pipeline Maatschap (50.00%)f
Maatschap Europoort Terminal (50.00%)f
Mach Monument Aviation Fuelling Co. Ltd. (70.00%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware 19902, United States
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Moezelweg 101, 3198LS Europoort, Rotterdam, Netherlands
Naz City, Building J, Suite 10 Erbil, Iraq
Malmo Fuelling Services AB (33.33%)
Box 22, SE 230 32 Malmö-Sturup, Sweden
Manchester Airport Storage and Hydrant Company Limited
(25.00%)
One Bartholomew Close , London, EC1A 7BL, United Kingdom
Manor Farm (Solar Power) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Manpetrol S.A. (50.00%)
Francisco Behr 20, Barrio Pueyrredon, Comodoro Rivadavia, Provincia del Chubut, Argentina
Maputo International Airport Fuelling Services (MIAFS)
Limitada (50.00%)b
Masana Employee Share Trust No. 1 (37.88%)b
Maverick Solar Class B, LLC (49.97%)b
Maverick Solar Construction, LLC (49.97%)b
Maverick Solar Holdings 1, LLC (49.97%)b
Maverick Solar Holdings 2, LLC (49.97%)b
Maverick Solar Holdings, LLC (49.97%)b
Mavrix, LLC (50.00%)b
McFall Fuel Limited (49.00%)
Mediteranean Gas Co. "MEDGAS" (25.00%)
Mehoopany Wind Energy LLC (50.00%)b
Mehoopany Wind Holdings LLC (50.00%)b
Meri Power Limited (49.97%)
Middle East Lubricants Company LLC (29.33%)
Mobene Beteiligungs GmbH & Co. KG (50.00%)f
Mobene Beteiligungs Verwaltungs GmbH (50.00%)
Mobene GmbH & Co. KG (50.00%)f
Mobene Verwaltungs-GmbH (50.00%)
Praca Dos Trabalhadores, Nr 09, Distrito Urbano 1, Maputo, Mozambique
199 Oxford Road, Oxford Parks, Dunkeld, Johannesburg, Gauteng, 2196, South Africa
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
KPMG, 247 Cameron Road, Tauranga, 3110, New Zealand
5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
6th Flr City Tower, 2 - Sheikh Zayed Road, PO Box 1699, Dubai, United Arab Emirates
Spaldingstraße 64, 20097 Hamburg, Germany
Spaldingstraße 64, 20097 Hamburg, Germany
Spaldingstraße 64, 20097 Hamburg, Germany
Spaldingstraße 64, 20097 Hamburg, Germany
Modelos Energéticos Sostenibles, S.L. (49.97%)
Calle Alcala numero 63, 28014, Madrid, Spain
MTS Francis Court Solar Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
296
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
MTS Trefinnick Solar Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
N.V. Rotterdam-Rijn-Pijpleiding Maatschappij (RRP)
(44.40%)
Butaanweg 215, NL-3196 KC Vondelingenplaat, Rotterdam, 3045, Havennummer , Netherlands
Natural Gas Vehicles Company "NGVC" (40.00%)
85 El Nasr Road, Cairo, Cairo, Egypt
New Zealand Oil Services Limited (50.00%)
Level 3, 139 The Terrace, Wellington, 6011, New Zealand
Nextpower Trevemper Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
NFX Combustíveis Marítimos Ltda. (50.00%)
Avenida Atlântica, no. 1.130, 2nd floor (part), Copacabana, Rio de Janeiro, RJ, 22021-000, Brazil
Nima Power Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Nord-West Oelleitung GmbH (59.33%)
Zum Ölhafen 207, 26384 Wilhelmshaven, Germany
Ocwen Energy Pty Ltd (49.50%)
Olympic Pipe Line Company LLC (70.00%)b
Oslo Lufthaven Tankanlegg AS (33.33%)
PAE E & P Bolivia Limited (50.00%)
PAE Oil & Gas Bolivia Ltda. (50.00%)
GTH Accounting Group Pty Ltd '2', 1A Kitchener Street, Toowoomba QLD 4350, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Postboks 134, Gardermoen, NO-2061, Norway
Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas
Cuarto anillo, Avda. Ovidio Barbery N° 4200, Edificio Torre , e/ Jaime Román y Victor Pinto, Equipetrol Norte,
Santa Cruz de la Sierra, Bolivia
Palk Power Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Pan American Energy Chile Limitada (50.00%)
Pan American Energy do Brasil Ltda. (50.00%)b
Pan American Energy Group, S.L. (50.00%)y
Nueva de Lyon Nº 145, piso 12, oficina 1203, Edificio Costa, Santiago de Chile, Chile
Rua Manoel da Nóbrega n°1280, 10° andar, Sao Paulo, Sao Paulo, 04001-902, Brazil
Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108 Alcobendas,
MADRID, SPAIN
Pan American Energy Holdings S.A. (50.00%)
Colonia 810, Oficina 403, Montevideo, Uruguay
Pan American Energy Iberica S.L. (50.00%)
Campus Empresarial Arbea - Edificio Nº 1, Carretera Fuencarral a Alcobendas (M-603), Km 3,8., Alcobendas,
Madrid, Spain
Pan American Energy Investments Ltd. (50.00%)
Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas
Pan American Energy Uruguay S.A. (50.00%)
Pan American Energy US LLC (51.00%)b
Pan American Energy, S.L. (50.00%)b
Colonia 810, Oficina 403, Montevideo, Uruguay
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Arbea Campus Empresarial, Edifico 1. Ctra de Fuencarral a Alcobendas, M603, KM 3,8 28108 Alcobendas,
MADRID, SPAIN
Pan American Fueguina S.A. (50.00%)
O´Higgins N° 194, Rio Grande, Argentina
Pan American Sur S.A. (50.00%)
O´Higgins N° 194, Rio Grande, Argentina
Parque Eolico Del Sur S.A. (27.50%)
Peninsular Aviation Services Company Limited (50.00%)i
Pentland Aviation Fuelling Services Limited (50.00%)c
Petrostock SA (50.00%)
Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina
P O Box 6369, Jeddah21442, Saudi Arabia
Suite 44 (C/O Best4Business Accountants), Beaufort Court, Admirals Way, London, E14 9XL, United Kingdom
route de Pré-Bois 2, 1214, Vernier, Switzerland
Pharaonic Petroleum Company "PhPC" (25.00%)
70/72 Road 200, Maadi, Cairo, Egypt
Pollon s.r.l. (32.48%)
Via Giacomo Leopardi 7, CAP 20123, Milan, Italy
Pont Andrew Limited (49.97%)
POPLAR SOLAR 1, LLC (49.97%)b
Porteiras Geração de Energia Ltda. (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Estrada BR 135, número S/N, KM 250, bairro / distrito Angico de Minas, município Japonvar - MG, CEP
39335-000, Brazil
Proteus Oil Pipeline Company, LLC (45.72%)b
PT Petro Storindo Energi (30.00%)
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Bakrie Tower 17th Floor, Rasuna Epicentrum Complex Jl. H.R Rasuna Said, Jakarta, 12940, Indonesia
PT. Dirgantara Petroindo Raya (49.90%)
Wisma AKR, 25th floor, Jalan Panjang No.5, Kebon Jeruk, , Jakarta Barat, 11530, Indonesia
Rahamat Petroleum Company (PETRORAHAMAT)
(50.00%)
70/72 Road 200, Maadi, Cairo, Egypt
Raststaette Glarnerland AG, Niederurnen (20.00%)
Nideracher 1, 8867, Niederurnen, Switzerland
RD Petroleum Limited (49.00%)
399 Moray Place, Dunedin, 9016, New Zealand
Reliance BP Mobility Limited (49.00%)
Resolution Partners LLP (68.00%)f
Rhein-Main-Rohrleitungstransportgesellschaft mbH
(35.00%)
3rd Floor, Maker Chambers IV, 222, Nariman Point, Mumbai, 400 021, India
1675 Broadway, Denver CO 80202, United States
Godorfer Hauptstraße 186, 50997 Köln, Germany
RMF Holdings Limited (49.00%)
KPMG, 247 Cameron Road, Tauranga, 3110, New Zealand
Romanian Fuelling Services S.R.L. (50.00%)
59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania
Rosneft Oil Company (19.75%)
Routex B.V. (25.00%)
26/1 Sofiyskaya Embankment, 115035, Moscow, Russian Federation, Russian Federation
Strawinskylaan 1725, 1077XX Amsterdam, Netherlands
S&JD Robertson North Air Limited (49.00%)
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
SABA- Sociedade Abastecedora de Aeronaves, Lda
(25.00%)
Grupo Operacional de Combustiveis do Aeroporto de Lisboa, Edificio 19, 1.º Sala Saba, Lisboa, Portugal
SAFCO SA (33.33%)
Salzburg Fuelling GmbH (33.00%)b
International airport "El. Venizelos", Athens, Greece
Innsbrucker Bundesstraße 95, 5020 Salzburg, Austria
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
297
14. Related undertakings of the group – continued
SAMCOL - Sociedade de Armazenamento e
Manuseamento de Combustiveis Liquidos, Limitada
(50.00%)b
Saraco SA (20.00%)
SeaPort Midstream Partners, LLC (49.00%)b
Sel PV 09 Limited (49.97%)
Servicios Logísticos de Combustibles de Aviación, S.L
(50.00%)
Parcela 729, via onze mil cento e trinta, numero cento e qua, Matola Lingamo, Mozambique
route de Pré-Bois 17, 1216, Cointrin, Switzerland
Cogency Global Inc., 850 New Burton Road, Suite 201, Dover, Delaware, 19904, United States
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Paseo de la Castellana 278, Madrid, Spain, Spain
Shakti Power Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Shandong Dongming Yinglun Petroleum Co., Ltd.
(49.00%)b
Sharjah Aviation Services Co. LLC (49.00%)y
Sharjah Pipeline Company LLC (49.00%)
Shell and BP South African Petroleum Refineries (Pty) Ltd
(37.50%)h
Shell Mex and B.P. Limited (40.00%)y
Shenzhen Cheng Yuan Aviation Oil Company Limited
(25.00%)b
Room B-703, B-704, B-705, B-706, B-707, Floor 7, Block B, No.8, Luoyuan Avenue, Lixia District, Jinan City,
China
P O Box- 97, Sharjah, United Arab Emirates
Sharjah 42244, Sharjah, UAE, Sharjah, United Arab Emirates
1 Refinery Road, Prospecton, 4110, South Africa
Shell Centre, London, SE1 7NA, United Kingdom
Fu Yong Town, Bao An county, ShenZhen Airport, Guangdong Province, China
Shenzhen Dapeng LNG Marketing Company Limited
(30.00%)b
Guangdong Dapeng Liquefied Natural Gas Filling Station, Cheng Tou Corner, Xia Sha Village, Dapeng Street,
Dapeng New District, Shenzhen, China
SKA Energy Holdings Limited (50.00%)
LOB 16, Suite #309, Jebel Ali Free Zone, Dubai, PO BOX 262794, United Arab Emirates
SM Realisations Limited (In Liquidation) (40.00%)
Shell International Petroleum, Co Ltd, Shell Centre, 8 York Road, London, SE1 7NA , United Kingdom
Société d'Avitaillement et de Stockage de Carburants
Aviation "SASCA" (40.00%)b
Société de Gestion de Produits Pétroliers - SOGEPP
(37.00%)
1 Place Gustave Eiffel, 94150, RUNGIS, France
27 Route du Bassin Numéro 6, 92230, GENNEVILLIERS, France
Solar Photovoltaic (SPV2) Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Solar Photovoltaic (SPV3) Limited (49.97%)
South Caucasus Pipeline Company Limited (28.83%)y
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
South Caucasus Pipeline Holding Company Limited
(28.83%)
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
South Caucasus Pipeline Option Gas Company Limited
(28.83%)
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
South China Bluesky Aviation Oil Company Limited
(24.50%)b
2-5F, No. 571, Yuncheng Dong Road, Baiyun District, Guangzhou City, Guangdong Province, China
Srednelenskoye Limited Liability Company (49.00%)
Kosmodamianskaya embarkment, 52 bldg 3, floor 9, unit 29, 115035, Moscow, Russian Federation
Stansted Intoplane Company Limited (20.00%)
Causeway House, 1 Dane Street, Bishop's Stortford, Hertfordshire, CM23 3BT, United Kingdom
STDG Strassentransport Dispositions Gesellschaft mbH
(50.00%)
Jenfelder Allee 80, 22039, Hamburg, Germany
Stockholm Fuelling Services Aktiebolag (25.00%)
Box 7, 190 45 Arlanda, Sweden
Sula Power Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sun and Soil Renewable 12 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Tankanlage AG Mellingen (33.33%)
Birmenstorferstrasse 2, 5507, Mellingen, Switzerland
TAR - Tankanlage Ruemlang AG (27.32%)
Zwüscheteich, 8153, Rümlang, Switzerland
TAU Tanklager Auhafen AG (50.00%)
Auhafenstrasse 10a, 4132, Muttenz, Switzerland
Team Terminal B.V. (22.80%)
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Tecklenburg GmbH (50.00%)
Tecklenburg GmbH & Co. Energiebedarf KG (50.00%)f
Terminal CP S.A.U. (50.00%)
Wesermünder Straße 1, 27729 Hambergen, Germany
Wesermünder Straße 1, 27729 Hambergen, Germany
Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina
Terminal de Combustiveis Paulinia S.A. (50.00%)
Avenida Paris, 4077, Suite 3, Cascata, Paulínia, São Paulo State, 13046-061, Brazil
Terminales Canarios, S.L. (50.00%)
TFSS Turbo Fuel Services Sachsen GbR (20.00%)f
TGC Solar 106 Limited (49.97%)
TGC Solar 91 Limited (49.97%)
TGH Tankdienst-Gesellschaft Hamburg GbR (66.67%)f
TGHL Tanklager-Gesellschaft Hannover-Langenhagen GbR
(50.00%)f
TGK Tanklagergesellschaft Koln-Bonn (25.00%)f
Thames Electricity Limited (49.97%)
The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)β
Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain
Sportallee 6, 22335 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Maples & Calder, P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman,
Cayman Islands
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
298
bp Annual Report and Form 20-F 2020
Financial statements
14. Related undertakings of the group – continued
The Consolidated Petroleum Company Limited (50.00%)y
The Consolidated Petroleum Supply Company Limited
(50.00%)ⳝ
The Great Ropemaker Partnership (50.00%)f
Thornton Transportation LLC (44.27%)b
Thorntons LLC (44.27%)b
TLK Holding Company LLC (44.27%)b
TLK Intermediate Holding Company LLC (44.27%)b
TLK Operating Company LLC (44.27%)b
TLM Tanklager Management GmbH (49.00%)b
TLS Tanklager Stuttgart GmbH (45.00%)
Shell Centre, London, SE1 7NA, United Kingdom
Shell Centre, London, SE1 7NA, United Kingdom
33 Cavendish Square, London, W1G 0PW, United Kingdom
Corporation Service Company, 421 West Main Street, Frankfort KY 40601, United States
CSC, 251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Am Tankhafen 4, 4020 Linz, Austria
Zum Ölhafen 49, 70327 Stuttgart, Germany
Tonatiuh Trading 1 Limited (49.97%)
TRaBP GbR (75.00%)f
Trafineo GmbH & Co. KG (75.00%)f
Trafineo Service GmbH (75.00%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Huestraße 25, 44787, Bochum, Germany
Wittener Straße 56, Bochum, Germany
Wittener Straße 45, 44789 Bochum, Germany
Trafineo Verwaltungs-GmbH (75.00%)
Wittener Straße 56, Bochum, Germany
Trans Adriatic Pipeline AG (20.00%)
Lindenstrasse 2, 6340 Baar, Switzerland
TransTank GmbH (50.00%)
Tuwale Power Limited (49.97%)
TWQE2 Limited (49.97%)
Am Stadthafen 60, 45881 Gelsenkirchen, Germany
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Ubiworx Systems Designated Activity Company (49.97%)
Trinity House, Charleston Road, Ranelagh, Dublin 6, D06C8X4, Ireland
United Gas Derivatives Company "UGDC" (33.33%)
Building No. 349 & 351, Third Sector of City Centre, Fifth Settlement, New Cairo, Egypt
United Kingdom Oil Pipelines Limited (22.15%)
5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom
Vale do Cochá Geração de Energia Ltda. (49.97%)
Estrada BR 030, número S/N, CXPST 08, bairro / distrito Zona Rural, município Montalvania - MG, CEP
39495-000, Brazil
Vendimia Grid, AIE (49.97%)
Ventress Solar Farm 1, LLC (49.97%)b
Verde Grande Geração de Energia Ltda. (49.97%)
Calle Alcala numero 63, 28014, Madrid, Spain
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Fazenda Contendas na Rodovia Joaquim de Freitas, sentido Mato Verde a Catut, Km 2 à direita, Zona Rural,
município de Mato Verde-MG, CEP 39527-000, Brazil
VIC CBM Limited (50.00%)
Vientos Ombu III S.A. (25.00%)
Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom
Av. Leandro N. Alem 1180, piso 11°, Buenos Aires, Argentina
Vientos Patagonicos Chubut Norte III S.A. (24.50%)
Lavalle 190, piso 6 Depto L, Buenos Aires, Argentina
Vientos Sudamericanos Chubut Norte IV S.A. (24.50%)
Lavalle 190, piso 6 Depto L, Buenos Aires, Argentina
Virginia Indonesia Co. CBM Limited (50.00%)
Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom
Walton-Gatwick Pipeline Company Limited (42.33%)
5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom
Wellington LandCo Pty Ltd (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Wellington North Solar Farm Pty Limited (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
West London Pipeline and Storage Limited (30.50%)
5-7 Alexandra Road, Hemel Hempstead, Herts., HP2 5BS, United Kingdom
West Wyalong FinCo Pty Ltd (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
West Wyalong Fund Pty Ltd (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
West Wyalong HoldCo 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
West Wyalong HoldCo 2 Pty Ltd (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
West Wyalong Trust (49.97%)
Whitetail Solar 1, LLC (24.99%)b
Whitetail Solar 2, LLC (24.99%)b
Whitetail Solar 3, LLC (24.99%)b
Whitetail Solar 6, LLC (49.97%)b
Whitetail Solar Land Holdings, LLC (49.97%)b
Wick Farm Grid Limited (24.99%)
Wildflower Solar 1, LLC (49.97%)b
Wildflower Solar Land Holdings, LLC (49.97%)b
Wiri Oil Services Limited (27.78%)
Woolooga FinCo Pty Ltd (49.97%)
Woolooga Fund Pty Ltd (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Woodwater House, Pynes Hill, Exeter, EX2 5WR, United Kingdom
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
251 Little Falls Drive, Wilmington, County of New Castle DE 19808, United States
Ross Pauling & Partners Limited, 106b Bush Road, Albany, Auckland, 0632, New Zealand
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Woolooga HoldCo 1 Limited (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
Woolooga HoldCo 2 Pty Ltd (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
Woolooga Trust (49.97%)
Your Power No. 1 Limited (49.97%)
Your Power No. 10 Limited (49.97%)
Your Power No. 19 Limited (49.97%)
Level 19 'CBW', 181 William Street, Melbourne VIC 3000, Australia
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020
299
14. Related undertakings of the group – continued
Your Power No. 2 Limited (49.97%)
Your Power No. 3 Limited (49.97%)
Your Power No. 8 Limited (49.97%)
Your Power No12 Limited (49.97%)
Zonneweide Westdorperveen B.V. (49.97%)
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HU, United Kingdom
7th Floor, 33 Holborn, London, EC1N 2HT, United Kingdom
Prins Bernhardplein 200
1097JB, Amsterdam, Netherlands
160 Greentree Drive, Suite 101, Dover, County of Kent DE 19904, United States
Zubie, Inc. (20.30%)
a Preference shares
b Member interest
c A and B shares
d Common stock and preference shares
e Ordinary shares and preference shares
f Partnership interest
g A, B and D shares
h A shares
i
Interest held directly by BP p.l.c.
j 99% held directly by BP p.l.c.
k 1% held directly by BP p.l.c.
l Ordinary, A and B shares
m Common stock and redeemable preference shares
n Ordinary A, B and C shares
o 0.008% held directly by BP p.l.c.
p 80.01% ordinary shares and 99.07% preference shares
q Members interest, (49.99%) subordinated units and (4.37%) common units traded on the New York stock exchange
r 93.64% ordinary shares and 81.18% preference shares
s Subsidiary in which the group does not hold a majority of the voting rights but exercises control over it
t Ordinary shares and redeemable preference shares
u Ordinary and A shares
v Ordinary and deferred shares
w 100% ordinary shares and 58.65% preference shares
x 15% held directly by BP p.l.c
y B shares
z Unlimited redeemable shares
⍺ 96.52% C shares
β 1.89% A shares and 40.80% B shares
γ 49.97% A shares, 50.00% C shares, 50.00% D shares, 50.00% E shares, 49.95% F shares and 50.00% G shares
ⳝ 5% held directly by BP p.l.c
The parent company financial statements of BP p.l.c. on pages 259-300 do not form part of bp’s Annual Report on Form 20-F as filed with the SEC.
300
bp Annual Report and Form 20-F 2020
Additional disclosures
Additional disclosures
Selected financial information
Liquidity and capital resources
Oil and gas disclosures for the group
Additional information for downstream
Additional information for Rosneft
Environmental expenditure
Regulation of the group’s business
International trade sanctions
Material contracts
Property, plant and equipment
Related-party transactions
Corporate governance practices
Code of ethics
Controls and procedures
Principal accountant’s fees and services
Directors’ report information
Disclosures required under Listing Rule 9.8.4R
Cautionary statement
302
306
308
318
320
321
321
325
326
326
326
326
326
326
327
327
328
329
bp Annual Report and Form 20-F 2020
301
Selected financial information
This information has been extracted or derived from the audited consolidated financial statements of the bp group. Note 1 to the financial statements
includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited
financial statements and related notes. The audited consolidated financial statements and related notes as of 31 December 2020 and 2019 and for the
three years ended 31 December 2020 are presented on page 130.
Income statement data
Sales and other operating revenues
Profit (loss) before interest and taxation
Finance costs and net finance expense relating to pensions and other post-
retirement benefits
Taxation
Non-controlling interests
Profit (loss) for the yeara
Inventory holding (gains) losses«, before tax
Taxation charge (credit) on inventory holding gains and losses
RC profit (loss)« for the year
Net (favourable) adverse impact of non-operating items« b and fair value
accounting effects« b, before tax
Taxation charge (credit) on non-operating items and fair value accounting
effects, and certain foreign exchange impacts on the group’s tax charge for
the period
Underlying RC profit« for the year
Earnings per sharec – cents
Profit (loss) for the yeara per ordinary share
Basic
Diluted
RC profit (loss) for the year per ordinary share«
Underlying RC profit for the year per ordinary share«
Dividends paid per share – cents
– pence
Capital expenditure« d
Organic capital expenditure«
Inorganic capital expenditure«
2020
2019
2018
2017
2016
$ million except per share amounts
180,366
(21,740)
278,397
11,706
298,756
19,378
240,208
9,474
183,008
(430)
(3,148)
4,159
424
(20,305)
2,868
(667)
(18,104)
(3,552)
(3,964)
(164)
4,026
(667)
156
3,515
(2,655)
(7,145)
(195)
9,383
801
(198)
9,986
(2,294)
(3,712)
(79)
3,389
(853)
225
2,761
(1,865)
2,467
(57)
115
(1,597)
483
(999)
16,649
8,263
3,380
3,730
6,746
(4,235)
(5,690)
(1,788)
9,990
(643)
12,723
(325)
6,166
(3,162)
2,585
(100.42)
(100.42)
(89.53)
(28.14)
31.50
24.458
12,034
2,021
14,055
19.84
19.73
17.32
49.24
41.00
31.977
15,238
4,183
19,421
46.98
46.67
50.00
63.70
40.50
30.568
15,140
9,948
25,088
17.20
17.10
14.02
31.31
40.00
30.979
16,501
1,339
17,840
0.61
0.60
(5.33)
13.79
40.00
29.418
16,675
777
17,452
Balance sheet data (at 31 December)
Total assets
Net assets
Share capital
bp shareholders’ equity
Finance debt due after more than one year
Gearing«
Ordinary share datae
Basic weighted average number of shares
Diluted weighted average number of shares
a Profit attributable to bp shareholders.
b See pages 304 and 305 for further analysis of these items.
c A reconciliation to GAAP information is provided on page 348.
d From 2017 onwards bp reports organic, inorganic and total capital expenditure on a cash basis which were previously reported on an accruals basis. This aligns with bp's financial framework and is
267,654
85,568
5,383
71,250
63,305
31.3%
295,194
100,708
5,404
98,412
57,237
31.1%
282,176
101,548
5,402
99,444
55,803
30.0%
276,515
100,404
5,343
98,491
54,873
27.0%
20,222
20,222
19,970
20,102
20,285
20,400
19,693
19,816
263,316
96,843
5,284
95,286
51,073
26.5%
Share million
18,745
18,855
consistent with other financial metrics used when comparing sources and uses of cash.
e The number of ordinary shares shown has been used to calculate the per share amounts.
302
bp Annual Report and Form 20-F 2020
« See Glossary
Additional information
Capital expenditure
Capital expenditure
Organic capital expenditure
Inorganic capital expenditureab
Organic capital expenditure by segment
Upstream
US
Non-US
Downstream
US
Non-US
Other businesses and corporate
US
Non-US
Organic capital expenditure by geographical area
US
Non-US
Additional disclosures
2020
2019
12,034
2,021
14,055
15,238
4,183
19,421
2020
2019
$ million
2018
15,140
9,948
25,088
$ million
2018
3,341
6,009
9,350
632
1,698
2,330
80
274
354
12,034
4,053
7,981
12,034
4,019
7,885
3,482
8,545
11,904
12,027
913
2,084
2,997
47
290
337
15,238
4,979
10,259
15,238
877
1,904
2,781
54
278
332
15,140
4,413
10,727
15,140
a On 31 October 2018, bp acquired from BHP Billiton Petroleum (North America) Inc. 100% of the issued share capital of Petrohawk Energy Corporation, a wholly owned subsidiary of BHP that holds a
portfolio of unconventional onshore US oil and gas assets. The entire consideration payable of $10,268 million, after customary closing adjustments, was paid in instalments between July 2018 and
April 2019. The amounts presented as inorganic capital expenditure include $3,480 million for 2019 and $6,788 million for 2018 relating to this transaction. 2018 includes $1,739 million relating to the
purchase of an additional 16.5% interest in the Clair field west of Shetland in the North Sea, as part of the agreements with Conoco-Phillips in which Conoco-Philips simultaneously purchased bp's
entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska. 2020, 2019 and 2018 also include amounts relating to the 25-year extension to our ACG production-sharing agreement«
in Azerbaijan.
b 2020 includes a $500 million deposit in respect of the strategic partnership with Equinor and $1 billion relating to an investment in a 49% interest in the group's Indian fuels and mobility venture with
Reliance industries.
« See Glossary
bp Annual Report and Form 20-F 2020
303
Non-operating items
Non-operating items are charges and credits included in the financial statements that bp discloses separately because it considers such disclosures to
be meaningful and relevant to investors. They are items that management considers not to be part of underlying business operations and are disclosed
in order to enable investors to understand better and evaluate the group’s reported financial performance. An analysis of non-operating items is shown
in the table below.
Upstream
Gain on sale of businesses and fixed assetsa
Impairment and losses on sale of businesses and fixed assetsa b
Environmental and other provisions
Restructuring, integration and rationalization costsc
Fair value gain (loss) on embedded derivatives
Otherd e
Downstream
Gain on sale of businesses and fixed assetsa f
Impairment and losses on sale of businesses and fixed assetsa
Environmental and other provisions
Restructuring, integration and rationalization costsc
Fair value gain (loss) on embedded derivatives
Other
Rosneft
Other
Other businesses and corporate
Gain on sale of businesses and fixed assetsa
Impairment and losses on sale of businesses and fixed assetsa g
Environmental and other provisionsh
Restructuring, integration and rationalization costsc
Fair value gain (loss) on embedded derivatives
Gulf of Mexico oil spill response
Otheri
Total before interest and taxation
Finance costsj
Total before taxation
2020
2019
$ million
2018
360
(13,214)
(2)
(401)
—
(2,511)
(15,768)
2,320
(1,136)
(33)
(633)
—
(39)
479
(205)
(205)
194
(19)
(177)
(262)
—
(255)
201
143
(7,036)
(32)
(89)
—
67
(6,947)
50
(122)
(78)
85
—
(12)
(77)
(103)
(103)
—
(917)
(231)
6
—
(319)
(30)
437
(527)
(35)
(131)
17
56
(183)
15
(69)
(83)
(405)
—
(174)
(716)
(95)
(95)
4
(264)
(640)
(190)
—
(714)
(159)
(318)
(15,812)
(625)
(16,437)
4,345
—
(99)
(12,191)
(1,491)
(8,618)
(511)
(9,129)
1,943
—
—
(7,186)
(1,963)
(2,957)
(479)
(3,436)
510
121
—
(2,805)
Taxation credit (charge) on non-operating items
Taxation - impact of US tax reformk
Taxation - impact of foreign exchangel
Total after taxation
a See Financial statements – Note 4 for further information.
b 2020 impairment charges for Upstream include $156 million in relation to the likely disposal of an exploration asset. 2019 includes impairments charges principally resulting from the announcements to
dispose of certain assets in the US and Egypt. 2018 includes an impairment reversal for assets in the North Sea and Angola.
c Restructuring charges are classified as non-operating items where they relate to an announced major group restructuring. A major group restructuring is a restructuring programme affecting more than
one of the group’s operating segments that is expected to result in charges of more than $1 billion over a defined period. 2020 includes recognized provisions for restructuring costs for plans that were
formalized during the year. 2018 includes amounts related to the programme originally announced in 2014 that was completed in 2018.
d 2020 includes exploration write-offs of $1,974 million relating to fair value ascribed to certain licences as part of the accounting at the time of acquisition of upstream assets in Brazil, India and the Gulf
of Mexico and the impairment of certain intangible assets in Mauritania and Senegal. 2018 includes exploration write-offs of $124 million in relation to the value ascribed to certain licences in the
deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011.
e 2020 includes $545 million net impairments reported by equity-accounted entities.
f 2020 includes a gain of $2.3 billion on the sale of our petrochemicals business.
g 2019 includes $877 million relating to the reclassification of accumulated foreign exchange losses from reserves to the income statement upon the contribution of our Brazilian biofuels business to BP
Bunge Bioenergia.
h All periods primarily reflect charges due to the annual update of environmental provisions, including asbestos-related provisions for past operations, together with updates of non-Gulf of Mexico oil spill
related legal provisions.
i From 2020, BP is presenting temporary valuation differences associated with the group’s interest rate and foreign currency exchange risk management of finance debt as non-operating items. These
amounts represent: (i) the impact of ineffectiveness and the amortisation of cross currency basis resulting from the application of fair value hedge accounting; and (ii) the net impact of foreign currency
exchange movements on finance debt and associated derivatives where hedge accounting is not applied. Relevant amounts in the comparative periods presented were not material.
j All periods presented include the unwinding of discounting effects relating to Gulf of Mexico oil spill payables. 2020 also includes the income statement impact associated with the buyback of finance
debt. See Note 26 for further information.
k In 2017 the US tax reform reduced the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. 2018 reflects a further impact following a clarification of the tax reform.
The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business operations, has a material impact upon the reported result and
is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate disclosure is considered meaningful and relevant to investors.
l From 2020, bp is presenting certain foreign exchange effects on tax as non-operating items. These amounts represent the impact of: (i) foreign exchange on deferred tax balances arising from the
conversion of local currency tax base amounts into functional currency, and (ii) taxable gains and losses from the retranslation of US dollar-denominated intra-group loans to local currency. Relevant
amounts in the comparative periods presented were not material.
304
bp Annual Report and Form 20-F 2020
« See Glossary
Non-GAAP information on fair value accounting effects
The impacts of fair value accounting effects, relative to management’s internal measure of performance, and a reconciliation to GAAP information is set
out below. Further information on fair value accounting effects is provided on page 344.
Additional disclosures
Upstream
Unrecognized (gains) losses brought forward from previous perioda
Favourable (adverse) impact relative to management’s measure of performance
Exchange translation gains (losses) on fair value accounting effects
Unrecognized (gains) losses carried forward
Downstream
Unrecognized (gains) losses brought forward from previous perioda
Favourable (adverse) impact relative to management’s measure of performance
Unrecognized (gains) losses carried forward
Other businesses and corporate
Favourable (adverse) impact relative to management’s measure of performanceb
Unrecognized (gains) losses carried forward
Favourable (adverse) impact relative to management’s measure of performance – by region
Upstream
US
Non-US
Downstream
US
Non-US
Other businesses and corporate
US
Non-US
Taxation credit (charge)
2020
2019
$ million
2018
253
(738)
—
(485)
104
(149)
(45)
675
675
198
(936)
(738)
27
(176)
(149)
—
675
675
(212)
(11)
(223)
(455)
706
2
253
(56)
160
104
—
—
(179)
885
706
148
12
160
—
—
—
866
(155)
711
(419)
(39)
3
(455)
(151)
95
(56)
—
—
(35)
(4)
(39)
(155)
250
95
—
—
—
56
12
68
a 2018 brought forward fair value accounting effect balances include a $55-million adjustment between Upstream and Downstream as part of the transfer of the NGL business between segments.
b From 2020 fair value accounting effects include changes in the fair value of derivatives entered into by the group to manage currency exposure and interest rate risks relating to hybrid bonds to their
respective first call periods. For further information see page 344.
Net debt including leases
Net debt including leases« is shown in the table below.
At 31 December
Net debt«
Lease liabilities
Net partner (receivable) payable for leases entered into on behalf of joint operations«
Net debt including leases
Total equity
Gearing including leases«
2020
38,941
9,262
(7)
48,196
85,568
36.0%
$ million
2019
45,442
9,722
(158)
55,006
100,708
35.3%
« See Glossary
bp Annual Report and Form 20-F 2020
305
Liquidity and capital resources
Financial framework
bp has a resilient financial framework that, taken together with our
strategy, creates a compelling investor proposition offering committed
distributions, profitable growth and sustainable value. The framework
comprises a coherent approach to capital allocation, a resilient balance
sheet, a disciplined approach to investment allocation and a relentless
focus on executing bp’s business plan.
bp’s approach to capital allocation leads to a clear set of priorities –
funding our resilient dividend as the first priority, deleveraging the balance
sheet, investment in low carbon« and convenience and mobility to
advance our energy transition strategy, investment in resilient
hydrocarbons to generate sustainable cash flow, and then returning
surplus cash« as share buybacks. In a period of low prices, the group
has the flexibility to reduce cash costs and to reduce or defer capital
investment, as appropriate.
Our shareholder distribution policy reflects these priorities for the uses of
cash alongside an ongoing consideration of factors, including changes in
the environment, the underlying performance of the business, the outlook
for the group financial framework, and other market factors which may
vary quarter to quarter.
Net debt« at 31 December 2020 was $38.9 billion and is expected to
reduce in line with the receipt of divestment proceeds and the growth in
operating cash flow« . bp is targeting $25 billion of proceeds by 2025
(from mid 2020), and at the end of 2020 bp had completed or agreed
transactions for over half of this target.
We expect operating cash flow to cover capital expenditure« and the
dividend, with capital expenditure initially in a range of $13-15 billion,
before increasing to $14-16 billion once net debt reaches $35 billion.
Capital expenditure is expected to be at the lower end of the initial range
in 2021. Looking further out across 2021-25, bp's cash balancing point is
expected to average around $40 per barrel (assuming an average refining
marker margin of around $11 and Henry Hub gas price at $3) in 2020 real
terms. Gulf of Mexico oil spill payments on a post-tax basis were just over
$1.6 billion in 2020 and are expected to be around $1 billion in 2021.
In 2020, the return on average capital employed« was (3.8)%a at an
average of $42 per barrel. The return on average capital employed is
targeted to grow to 12-14% by 2025 at $50 to 60 per barrel in 2020 real
terms, and assuming bp planning assumptions, as we continue to
execute our strategy. This is supported by an expected 7-9% growth in
earnings before interest, tax, depreciation and amortization (compound
annual growth rate) across the same period and subject to the same price
and planning assumptions.
a Nearest equivalent GAAP measures: Numerator – Loss attributable to bp shareholders $(20.3);
Denominator – Average capital employed $163.3 billion.
Dividends and other distributions to shareholders
The dividend is determined in US dollars, the economic currency of bp,
and the dividend level is reviewed by the board each quarter. The
quarterly dividend was reset to 5.25 cents per ordinary share per quarter
as part of a wider distribution policy announced in August 2020, and is
intended to remain fixed at this level.
The total dividend distributed to bp shareholders in 2020 was $6.4 billion
(2019 $8.3 billion). This dividend was all paid in cash as shareholders no
longer have the option to receive a scrip dividend in place of receiving
cash.
Included in the distribution policy is a commitment that, once net debt
reaches $35 billion and subject to maintaining a strong investment grade
credit rating, at least 60% of surplus cash will be distributed to
shareholders through share buybacks.
The share buyback programme to offset the dilutive impact of the legacy
scrip dividend concluded in January 2020 and purchased 120 million
ordinary shares in 2020 at a cost of $776 million (2019 $1.5 billion),
including fees and stamp duty.
Financing the group’s activities
The group’s principal commodities, oil and gas, are priced internationally
in US dollars. Group policy has generally been to minimize economic
exposure to currency movements by financing operations with US dollar
debt. Where debt and hybrid bonds are issued in other currencies, they
are generally swapped back to US dollars using derivative contracts, or
else hedged by maintaining offsetting cash positions in the same
currency. Cash balances of the group are mainly held in US dollars or
swapped to US dollars and holdings are well diversified to reduce
concentration risk. The group is not, therefore, exposed to significant
currency risk regarding its cash or borrowings. Also see Risk factors on
page 67 for further information on risks associated with prices and
markets and Financial statements – Note 29.
The group’s finance debt at 31 December 2020 amounted to $72.7 billion
(2019 $67.7 billion). Of the total finance debt, $9.4 billion is classified as
short term at the end of 2020 (2019 $10.5 billion). See Financial
statements – Note 26 for more information on the short-term balance.
Net debt« was $38.9 billion at the end of 2020, a decrease of $6.5 billion
from the 2019 year-end position of $45.4 billion.
On 17 June 2020, a group subsidiary« issued perpetual subordinated
hybrid bonds in EUR, GBP and USD for a US dollar equivalent amount of
$11.9 billion. As the group has the unconditional right to avoid transferring
cash or another financial asset in relation to these hybrid bonds, they are
classified as equity instruments and reported within non-controlling
interests.
The ratio of finance debt to finance debt plus total equity at 31 December
2020 was 45.9% (2019 40.2%). Gearing was 31.3% at the end of 2020
(2019 31.1%). See Financial statements – Note 27 for finance debt, which
is the nearest equivalent measure on an IFRS basis, and for further
information on net debt.
Cash and cash equivalents of $31.1 billion at 31 December 2020 (2019
$22.5 billion) are included in net debt. We manage our cash position so
that the group has adequate cover to respond to potential short-term
market liquidity, short term price environment volatility and expect to
maintain a robust cash position.
The group also has an undrawn committed $8 billion credit facility and
undrawn committed bank facilities of $4 billion (see Financial statements
– Note 29 for more information).
We believe that the group has sufficient working capital for foreseeable
requirements, taking into account the amounts of undrawn borrowing
facilities and levels of cash and cash equivalents, and its ongoing ability to
generate cash.
bp utilizes various arrangements in order to manage its working capital
including discounting of receivables and, in the supply and trading
business, the active management of supplier payment terms, inventory
and collateral.
Standard & Poor’s Ratings’ long-term credit rating for BP p.l.c. is A-
(negative outlook), the Moody’s Investors Service rating is A1 (negative
outlook) and the Fitch Ratings’ long-term credit rating is A (stable).
The group’s sources of funding, its access to capital markets and
maintaining a strong cash position are described in Financial statements –
Note 25 and Note 29. Further information on the management of liquidity
risk and credit risk, and the maturity profile and fixed/floating rate
characteristics of the group’s debt are also provided in Financial
statements– Note 26 and Note 29.
The information above contains forward-looking statements, which by their nature involve risk and uncertainty because they relate to events and
depend on circumstances that will or may occur in the future and are outside the control of bp. You are urged to read the Cautionary statement on page
329 and Risk factors on page 67, which describe the risks and uncertainties that may cause actual results and developments to differ materially from
those expressed or implied by these forward-looking statements.
306
bp Annual Report and Form 20-F 2020
« See Glossary
Off-balance sheet arrangements
At 31 December 2020, the group’s share of third-party finance debt of equity-accounted entities was $19.9 billion (2019 $17.3 billion). These amounts
are not reflected in the group’s debt on the balance sheet. The group has issued third-party guarantees under which amounts outstanding, incremental
to amounts recognized on the balance sheet, at 31 December 2020 were $1,405 million (2019 $692 million) in respect of liabilities of joint ventures«
and associates« and $661 million (2019 $523 million) in respect of liabilities of other third parties. Of these amounts, $1,393 million (2019 $681
million) of the joint ventures and associates guarantees relate to borrowings and for other third-party guarantees, $568 million (2019 $494 million) relate
to guarantees of borrowings.
Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2020 and the
proportion of that expenditure for which contracts have been placed.
Additional disclosures
Capital expenditure
Committed
of which is contracted
Total
18,025
8,009
2021
9,016
4,878
2022
5,467
2,805
2023
1,747
166
2024
747
65
$ million
Payments due by period
2025
505
27
2026 and
thereafter
543
68
Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. For joint
operations«, the net bp share is included in the amounts above.
In addition, at 31 December 2020, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to
$3,774 million. Contracts were in place for $1,270 million of this total.
The following table summarizes the group’s principal contractual obligations at 31 December 2020, distinguishing between those for which a liability is
recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial statements –
Note 26 and more information on leases is given in Financial statements – Note 28.
$ million
Payments due by period
Expected payments by period under contractual obligations
Total
2021
2022
2023
2024
2025
Balance sheet obligations
Borrowingsa
Lease liabilitiesb
Decommissioning liabilitiesc
Environmental liabilitiesc
Gulf of Mexico oil spill liabilitiesd
Pensions and other post-retirement benefitse
Off-balance sheet obligations
Unconditional purchase obligationsf
Crude oil and oil products
Natural gas and LNG
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
81,076
10,884
22,466
1,880
14,569
17,448
148,323
13,981
2,262
470
272
1,409
1,039
19,433
7,541
1,672
244
290
1,278
978
12,003
8,146
1,340
279
242
1,222
946
12,175
9,001
1,025
233
196
1,141
922
12,518
7,445
878
221
157
1,136
917
10,754
2026 and
thereafter
34,962
3,707
21,019
723
8,383
12,646
81,440
44,322
35,337
684
4,240
762
19,270
19,830
124,445
272,768
35,702
11,255
422
2,124
91
1,792
2,810
54,196
73,629
4,495
4,779
70
730
91
1,529
2,010
13,704
25,707
1,988
3,155
63
364
53
1,459
1,628
8,710
20,885
993
2,442
54
176
51
1,357
1,358
6,431
18,949
477
1,465
53
193
50
1,189
1,207
4,634
667
12,241
22
653
426
11,944
10,817
36,770
15,388 118,210
Total
a Expected payments include interest totalling $8,412 million ($1,503 million in 2021, $1,249 million in 2022, $1,115 million in 2023, $954 million in 2024, $793 million in 2025 and $2,798 million
thereafter).
b Expected payments include interest totalling $1,622 million ($275 million in 2021, $228 million in 2022, $190 million in 2023, $156 million in 2024, $126 million in 2025 and $647 million thereafter).
c The amounts presented are undiscounted.
d The amounts presented are undiscounted. Gulf of Mexico oil spill liabilities are included in the group balance sheet, on a discounted basis, within other payables. See Financial statements – Note 22 for
further information.
e Represents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post-retirement benefits.
f Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms (such as fixed or minimum purchase volumes, timing of purchase
and pricing provisions). Agreements that do not specify all significant terms, or that are not enforceable, are excluded. The amounts shown include arrangements to secure long-term access to supplies
of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2021 include purchase commitments existing at 31 December 2020 entered into principally to meet the
group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements – Note 29.
Commitments for the delivery of oil and gas
We sell crude oil, natural gas and liquefied natural gas under a variety of contractual obligations. Some of these contracts specify the delivery of fixed
and determinable quantities. For the period from 2021 to 2023 worldwide, we are contractually committed to deliver approximately 228 million barrels
of oil, 8,500 billion cubic feet of natural gas, and 37 million tonnes of liquefied natural gas. The commitments principally relate to group subsidiaries«
based in Canada, Egypt, Singapore, United Kingdom and United States. We expect to fulfil these delivery commitments with production from our
proved developed reserves and supplies from existing contracts, supplemented by market purchases as necessary.
« See Glossary
bp Annual Report and Form 20-F 2020
307
Oil and gas disclosures for the group
Analysis by region
Our oil and gas operations are set out below by geographical area, with
associated significant events for 2020. bp’s percentage working interest
in oil and gas assets is shown in brackets. Working interest is the cost-
bearing ownership share of an oil or gas lease. Consequently, the
percentages disclosed for certain agreements do not necessarily reflect
the percentage interests in proved reserves, production or revenue. See
page 320 for more information on Rosneft.
In addition to exploration, development and production activities, our
Upstream business also includes certain midstream and liquefied natural
gas (LNG) supply activities. Midstream activities involve the ownership
and management of crude oil and natural gas pipelines, processing
facilities and export terminals, LNG processing facilities and
transportation, and our natural gas liquids (NGLs) processing business.
Our LNG activities are located in Abu Dhabi, Angola, Australia, Indonesia
and Trinidad. In 2020 we marketed around 5.0 million tonnes of LNG
production from these assets to IST which supplements equity production
with merchant third party volumes to build a global trading portfolio. The
LNG is marketed through contractual rights to access import terminal
capacity in the liquid markets of Europe, UK and US, and relationships to
market directly to end user customers or trading entities. LNG is supplied
to all major LNG demand centres for example Argentina, Brazil,
Caribbean, China, Croatia, Mediterranean and North West Europe, India,
Israel, Japan, Singapore, South Korea, Taiwan, Thailand, Turkey and the
UK.
Europe
bp is active in the North Sea and the Norwegian Sea. In 2020 bp’s
production came from three key areas: the Shetland area comprising the
Clair, Foinaven, and Schiehallion fields; the central area comprising the
Andrew area, Culzean, ETAP and Shearwater fields; and Norway, through
our equity accounted 30% interest in Aker BP.
• On 29 March, bp confirmed completion of the restructuring of
contractual arrangements for the Petrojari Foinaven floating production,
storage and offloading vessel on the Foinaven field to the west of the
Shetlands (bp 72% and operator).
bp has around 260 lease blocks in the Gulf of Mexico and operates four
production hubs.
• On 25 August, bp confirmed it started production at Atlantis Phase 3 in
the US Gulf of Mexico (bp 56% and operator).
• Construction and installation at the Thunder Horse South Expansion
Phase 2 project is underway and drilling set to commence in the first
half of 2021. First oil from the project is expected in the third quarter of
2021.
• bp was awarded 12 leases in the lease sale conducted in March and 10
leases in the sale held in November.
• The Mad Dog 2 project execute timeline was impacted by both
COVID-19 and delays to fabrication of the floating production unit. The
unit has now set sail from Korea, and wells activity and subsea
installation are once again progressing. First oil is now expected in the
second quarter of 2022.
• During the year, exploration write-offs of $2,643 million were
recognized in relation to certain Gulf of Mexico assets, primarily due to
management's re-assessment of expectations to extract value from
certain exploration prospects as a result of a review of the group's long-
term strategic plan and changes in the group's long-term price
assumptions.
See also Financial Statements – Note 1 for further information on
exploration leases.
bpx energy, bp's onshore oil and gas business in the Lower 48 states, has
significant operated and non-operated activities across Louisiana, Texas
and Wyoming producing natural gas, oil, NGLs and condensate, with
primary focus on developing unconventional resources in Texas. It had a
1.5 billion boe proved reserve base at 31 December 2020, predominantly
in unconventional reservoirs (tight gas«, shale gas and newly acquired
shale oil). BPX Energy's assets span 2.1 million net developed acres and it
had over 7,000 operated gross wells at 31 December 2020, with daily net
production around 370mboe/d.
bpx energy operated as a separate business in 2020 while remaining part
of the Upstream segment. With its own governance, systems and
processes, it is structured to increase competitive performance through
swift decision making and innovation, while maintaining bp’s commitment
to safe, reliable and compliant operations.
• During the year, impairment charges of $2,796 million were recognized
in respect of certain North Sea assets, primarily as a result of changes
to the group's long-term price assumptions.
• During the year, impairment charges of $1,444 million were recognized
in respect of certain bpx energy assets, primarily as a result of changes
to the group's long term price assumptions.
• In March 2020, EnQuest, the Thistle field operator, announced it no
longer expected to re-start production at the Thistle field (bp 82%) . A
Cessation of Production application was approved by the regulator in
July, with an effective decommissioning date of 31 May 2020.
• During the third quarter, bp was awarded eight operated and three non-
operated blocks in the North Sea as part of the UK Oil & Gas Authority
32nd offshore licensing round.
• On 6 October, bp confirmed that the planned divestment to Premier Oil
of its interests in the Andrew area and Shearwater assets, both located
in the UK North Sea, would not proceed following the announcement
of a proposed merger between Chrysaor and Premier Oil. bp had
announced this divestment in January 2020. The divestment was to
cover the Andrew, Arundel, Cyrus, Farragon and Kinnoull fields plus
bp's interest in Shearwater. Marketing of both assets continues.
• On 26 November, bp announced that production had started at the
Vorlich field (bp 66%), just two years after the project was sanctioned.
Vorlich is the latest in a programme of fast-paced, high-return subsea
tiebacks in the UK North Sea. bp and partner Ithaca Energy invested
£230 million to develop the field, which was discovered in 2014 and
received regulatory approval for development in 2018.
North America
Our upstream activities in North America are located in four areas:
deepwater Gulf of Mexico, the Lower 48 states, Canada and Mexico. Our
interests in Alaska were disposed of during the year, further details are
provided below.
• In December bp announced that it had reached agreement to sell its
interest in the Wamsutter asset in Wyoming to Williams Field Services
LLC. The transaction completed in January 2021.
bp’s onshore US crude oil and product pipelines and related transportation
assets were included in the Downstream segment in 2020.
In Alaska, BP Exploration (Alaska) Inc. (BPXA) operated nine North Slope
oilfields in the Greater Prudhoe Bay area and held interests in three
producing fields operated by others, as well as a non-operating interest in
the Liberty development project prior to the completion in the second
quarter of 2020 of the divestment of its Upstream business to Hilcorp
Energy announced in 2019.
BP Pipelines (Alaska) Inc. (BPPA) owned a 49% interest in the Trans-
Alaska Pipeline System (TAPS) prior to completion in the fourth quarter of
2020 of the divestment of its Midstream interests to Hilcorp Energy
announced in 2019. As part of this transaction impairments of $1,002
million were recognized in 2020. bp retained the decommissioning liability
relating to its interest in TAPS which will be partially offset by a 30%
reimbursement of costs incurred from Hilcorp.
In Canada bp is focused on pursuing offshore exploration opportunities
and its Sunrise Oil Sands operations. We have offshore exploration
licences in Nova Scotia, Newfoundland and Labrador and the Canadian
Beaufort Sea. In addition to Sunrise Oil Sands we hold interests in two
further oil sands lease areas through the Terre de Grace partnership and
the Pike Oil Sands joint operation«. In-situ steam-assisted gravity
drainage (SAGD) technology is utilized in our existing oil sands operations,
which uses the injection of steam into the reservoir to warm the bitumen
so that it can flow to the surface through producing wells.
308
bp Annual Report and Form 20-F 2020
« See Glossary
• The order issued by the government of Canada in 2019 prohibiting any
work or activity authorized under the Canada Oil and Gas Operations
Act on frontier lands that are situated in Canadian Arctic offshore
waters remains in effect until 31 December 2021.
• During the year, impairment charges of $865 million were recognized in
respect of certain assets in Canada, primarily as a result of changes to
the group's long-term price assumptions.
• Also during the year, exploration write-offs of $2,539 million were
recognized in relation to certain assets in Canada following
management's re-assessment of expectations to extract value from
certain exploration prospects as a result of a review of the group's long-
term strategic plan and changes in the group's long-term price
assumptions. A $247-million write-off was also recognized in relation to
a prepayment for the Pike access pipeline.
• On 29 October, bp confirmed oil discoveries at the Cappahayden and
Cambriol prospects in the Flemish Pass basin (bp 40%), offshore
Newfoundland.
In Mexico, we have interests in two exploration joint operations in the
Salina Basin with Equinor and Total, Block 1 (bp 33% and operator) and
Block 3 (bp 33%), and in one exploration joint operation in the Sureste
Basin with Total and Hokchi, a subsidiary of Pan American Energy Group
(PAEG), Block 34 (bp 42.5% and operator).
South America
bp has upstream activities in Argentina, Brazil and Trinidad & Tobago and
through PAEG, in Argentina, Bolivia and Uruguay.
In Argentina bp and Total are partners on a 50/50 basis in two offshore
exploration concessions. Total is the operator.
In Brazil bp has interests in 22 exploration concessions across five basins.
• During the year, exploration write-offs of $2,141 million were
recognized in relation to certain assets in Brazil following
management's re-assessment of expectations to extract value from
certain exploration prospects as a result of a review of the group's long-
term strategic plan and changes in the group's long-term price
assumptions.
• In the Foz do Amazonas basin, Total's request for a license extension
for blocks FZA-M-57, 86, 88, 125 and 127was approved by the Brazilian
regulatory authorities. Following their resignation from operatorship in
August, Total reached agreement in October to transfer its working
interest in these blocks to Petrobras. This transfer was also approved
by the regulatory authorities.
• In FZA-M-59 block, bp requested a two year license extension to May
2022 which was approved by the ANP in June, based on Resolution
708/2017. bp also transferred its operatorship of this block to Petrobras,
and this was approved by the ANP in October.
• bp reached an agreement to sell Itaipu and Wahoo exploration assets to
PetroRio for $100 million to be paid in instalments from 2021 onwards;
a further $40 million payment is contingent on pre-agreed conditions.
The completion of this transaction is subject to the approval from the
Brazilian regulatory authorities.
PAEG, a joint venture that is owned by bp (50%) and Bridas Corporation
(50%), has activities mainly in Argentina and Mexico, but is also present in
Uruguay and Bolivia.
• On 24 May, the Hokchi project in Mexico, operated by PAEG, achieved
first oil, producing 1.2mboe/d in 2020.
In Trinidad & Tobago bp holds interests in exploration and production
licences and production-sharing contracts« (PSCs) covering 1.6
million acres offshore of the east and north-east coast. Facilities include
15 offshore platforms and two onshore processing facilities. Production
comprises gas and associated liquids.
bp also holds interests in the Atlantic LNG facility. bp’s shareholding
averages 39% across four LNG trains« with a combined capacity of
approximately 15 million tonnes per annum. During 2020 we sold gas to
trains 1, 2 and 3 and processed gas in train 4. Most of the LNG produced
from bp gas supplied to trains 2, 3 and 4 is sold to third parties under
long- term contracts.
Additional disclosures
• The Cassia Compression project, a new compression platform with a
1.2bcf/d capacity bridge-linked to the Cassia B processing platform was
expected to start up in 2021 but is delayed to 2022 as a result of
COVID-19 impacting delivery lines.
• Impairment charges of $2,416 million were recognized in 2020 in
respect of certain assets in Trinidad, primarily as a result of changes to
the group's long-term price assumptions.
• bp holds a 30% interest in two deepwater blocks, Block 23(a) and
TTDAA14, with BHP as the Operator holding a 70% interest. There
were four successful exploration wells drilled in 2019 and appraisal
work is ongoing on these discoveries.
• bp’s initial gas sales and LNG offtake arrangements for Atlantic LNG
Train 1 ended in September 2018. Subsequently, short term gas sales
and LNG offtake arrangements were established and rolled over up
until December 2020, with bp lifting the majority of the LNG produced.
The National Gas Company of Trinidad & Tobago (NGC) has agreed to
fund the operating cost of Train 1 up to the end of December 2021 for
the right but not the obligation to supply gas into Train 1 and offtake
100% of the resultant LNG.
• On 28 September, BP Trinidad and Tobago LLC started up the Galeota
expansion project in Trinidad. The project comprises a new produced
water handling facility, a new flare system, relocation of the control
room away from production and upgrades to the existing condensate
stabilization facility.
• bp is operator of the Manakin Block which was discovered in 1998 and
is a cross border reservoir field with the Venezuelan reservoir, Cocuina.
Manakin declared commerciality in January 2018 however cross border
discussions have not progressed due to the US sanctions.
Africa
bp’s upstream activities in Africa are located in Algeria, Angola, Côte
d'Ivoire, Egypt, The Gambia, Libya, Mauritania, São Tomé & Príncipe and
Senegal. bp's interest in Madagascar was relinquished in 2020.
In Algeria bp, Sonatrach and Equinor are partners in the In Salah (bp
33.15%) and In Amenas (bp 45.89%) non-operated joint ventures that
supply gas to the domestic and European markets.
In Angola, bp owns an interest in five major deepwater offshore licences
and is operator in two of these, Blocks 18 and 31, that are producing. We
also have an equity interest in the Angola LNG plant (bp 13.6%).
• During the year, exploration write-offs of $832 million were recognized
in relation to certain assets in Angola following management's re-
assessment of expectations to extract value from certain exploration
prospects as a result of a review of the group's long-term strategic plan
and changes in the group's long-term price assumptions.
• Also during the year, impairment charges of $316 million were
recognized in relation to certain assets in Angola, primarily as a result of
changes to the group's long-term price assumptions.
• Development progressed at the Total-operated Zinia 2 deep offshore
development project in Block 17 (bp 15.84%) and first production is
expected in 2021.
• During the year, construction activity started at the Platina project in
Block 18, with first production expected in 2022.
• Following the signing of an agreement in December 2019 by bp and its
partners with the Agência Nacional de Petróleo, Gás e Biocombustíveis
(ANPG), to extend the production-sharing agreement« (PSA) for
Block 17 until 2045, all conditions precedent relating to the agreement
were met in the second quarter of 2020 and the new agreement
became effective on 1 April 2020. Under the agreement the state-
owned company Sonangol acquired a 5% equity interest in the block on
the effective date with a further 5% to be transferred in 2036.
• In June 2019, bp and the contractor group signed an agreement with
ANPG, extending the PSA for Block 15 until 2032. Under the
agreement Sonangol acquired a 10% equity interest in the block,
reducing bp’s interest from 26.67% to 24%. All conditions precedent
relating to the agreement were met on 27 January 2020 and the new
agreement became effective as from 1 October 2019.
« See Glossary
bp Annual Report and Form 20-F 2020
309
• In December 2018, bp and the contractor group signed an agreement
with ANPG, extending the Block 18 PSA until 2032. Under the
agreement, effective from 1 July 2020, Sonangol acquired an 8%
equity interest in the block, reducing bp’s interest from 50% to 46%.
All conditions precedent relating to the agreement were met on 17
December 2020.
In Côte d’Ivoire, bp has interests in five offshore oil blocks with Kosmos
Energy (KE) under agreements with the government of Côte d'Ivoire and
the state oil company Société Nationale d'Operations Pétrolières de la
Côte d'Ivoire (PETROCI) (bp 45%).
In Egypt, bp and its partners currently produce 60% of Egypt’s gas
production.
• During the year, exploration write-offs of $952 million were recognized
in relation to certain assets in Egypt following management's re-
assessment of expectations to extract value from certain exploration
prospects as a result of a review of the group's long-term strategic plan
and changes in the group's long-term price assumptions.
• In July, bp confirmed the Bashrush gas discovery, located offshore
Egypt in the North El Hammad concession (bp 37.5%).
• On 16 September, bp confirmed a gas discovery with the Nidoco NW-1
exploratory well in the Abu Madi West development lease, offshore
Egypt (bp 25%).
• On 26 October bp announced the start-up of gas production from the
Qattameya gas field in the North Damietta offshore concession (bp
100%). Qattameya, whose discovery was announced in 2017, is
located approximately 45 km west of the Ha’py platform and is tied
back to the Ha’py and Tuart field development via a new 50km pipeline.
• Work on the West Nile Delta Raven project (BP 82.75%) is almost
complete, with start up expected in the first quarter of 2021. Raven is
the third project in North Alexandria and West Mediterranean
deepwater offshore blocks.
In the Gambia, bp has a 90% interest in offshore block A1 with the state
oil company, Gambia National Petroleum Corporation.
In Libya, bp partners with the Libyan Investment Authority (LIA) in an
exploration and production sharing agreement (EPSA) to explore acreage
in the onshore Ghadames and offshore Sirt basins (bp 85%). bp wrote off
all balances associated with the Libya EPSA in 2015.
• bp, LIA and Eni continue to work with the NOC towards Eni acquiring a
42.5% interest in the bp-operated EPSA in Libya. On completion, Eni
would become operator of the EPSA. The companies are continuing to
work together to finalize and complete all agreements.
In Mauritania and Senegal, bp has a 62% participating interest in the C8,
C12 and C13 exploration blocks in Mauritania and a 60% participating
interest in the Cayar Profond Offshore and St Louis Profond Offshore
exploration blocks in Senegal. We relinquished our interest in the C6
exploration block in October. Together the remaining blocks cover
approximately 19,700 square kilometres. For the Greater Tortue Ahmeyin
(GTA) Unit across the border of Mauritania and Senegal, bp has a 56%
participating interest.
The Phase 1 construction activity for the GTA major project« was
severely affected by COVID-19 and the 2020 weather window for
installation works was not met resulting in a delay to start up of around
one year. A force majeure (FM) notice was issued under the lease and
operate agreement with Golar LNG over the provision of a floating
liquified natural gas vessel, where due to the FM event the lessee was
not able to meet the connection date. On 1 October, bp confirmed force
majeure was lifted on the project.
• During the first quarter, bp executed a gas sale and purchase
agreement with partners in the Greater Tortue Ahmeyim (GTA) project.
• During the year, impairment charges and an exploration write-off
totalling $2,260 million were recognized in respect of certain assets in
the region, primarily as a result of changes to the group's long-term
price assumptions.
In Madagascar, during the second quarter, following management's re-
assessment of expectations to extract value from certain exploration
prospects as a result of a review of the group's long-term strategic plan
and changes in the group's long-term price assumptions, bp relinquished
its interest in three PSCs (the fourth was relinquished in February 2020)
for exploration licences situated offshore northwest Madagascar, under
agreements with the government of Madagascar represented by Office
des Mines Nationales et des Industries Stratégiques (OMNIS) (bp 100%).
In São Tomé & Príncipe, bp is operator in two offshore blocks under PSAs
with Shell who acquired the interests of KE in December 2020, and the
state oil company Agencia Nacional do Petroleo (bp 50%).
Asia
bp has activities in Abu Dhabi, Azerbaijan, China, India, Indonesia, Iraq,
Kuwait, Oman and Russia.
In China we have a 30% equity stake in the Guangdong LNG
regasification terminal and trunkline project with a total storage capacity
of 640,000 cubic metres. The project is supplied under a long-term
contract with Australia’s North West Shelf venture (bp 16.67%).
In Azerbaijan, bp operates two PSAs, Azeri-Chirag-Gunashli (ACG) (bp
30.37%) and Shah Deniz (bp 28.83%) and also holds a number of other
exploration leases.
• Naftiran Intertrade Co Ltd (NICO), a subsidiary of the National Iranian Oil
Company, holds a 10% interest in the Shah Deniz joint venture. For
information on the exclusion of this project from EU and US trade
sanctions, or exemptions from such trade sanctions in relation to this
project, see International trade sanctions on page 325.
• During the year, impairment charges of $537 million were recognized
in respect of certain assets in the region, primarily as a result of
changes to the group's long-term price assumptions.
• In January 2020 bp announced that drilling of the first well on the
Shafag-Asiman offshore block had commenced. The drilling of the
SAX01 well continued in 2020 and we expect it to reach the target
depth in the first half of 2021.
bp holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan oil
pipeline. The 1,768-kilometre pipeline transports oil from the bp-operated
ACG oilfield and gas condensate from the Shah Deniz gas field in the
Caspian Sea, along with other third-party oil, to the eastern Mediterranean
port of Ceyhan. The pipeline has a capacity of 1mmboe/d, with an average
throughput in 2020 of 570mboe/d.
bp (as operator of Azerbaijan International Operating Company) also
operates the Western Route Export Pipeline that transports ACG oil to
Supsa on the Black Sea coast of Georgia, with an average throughput of
85mboe/d in 2020.
bp holds a 28.83% interest in and performs some operations for the 693
kilometre South Caucasus Pipeline. The pipeline takes gas from
Azerbaijan through Georgia to the Turkish border and has a capacity of
440mboe/d (including expansion), with average throughput in 2020 of
210mboe/d.
bp also holds a 12% interest in the Trans Anatolian Natural Gas Pipeline
(TANAP). In the first phase, which commenced in 2018, gas from Shah
Deniz is transported to Eskisehir in Turkey. The capacity of the pipeline
during the first phase is 100mboe/d and the average throughput in 2020
was 80mboe/d. The second phase takes gas further to TANAP's
connection with the Trans Adriatic Pipeline (TAP) at the Turkey-Greece
border. bp has a 20% interest in TAP, that takes gas through Greece and
Albania into Italy. Commercial deliveries of gas via TAP commenced at the
end of 2020.
In Oman bp operates Block 61, the largest tight gas« development in the
Middle East (bp 60%), and is a 50% owner in Block 77.
• The Block 77 Exploration and PSA was approved by Royal Decree in the
first quarter of 2020, with a plan to process seismic and drill one
exploration well within the next three years. ENI (50%) is operator
during the exploration phase and bp will be the operator of any potential
development.
• On 12 October, bp announced production had begun from the Block 61
Phase 2 Ghazeer gas field, around 33 months after bp and its partners
approved the development. bp brought the project online ahead of the
original planned start-up in early 2021, and under budget.
• On 1 February 2021 bp announced that it had agreed to sell a 20%
participating interest in Block 61 to PTT Exploration and Production
310
bp Annual Report and Form 20-F 2020
« See Glossary
Public Company Limited (PTTEP) of Thailand for a total consideration of
$2.6 billion. Following completion of the sale, which is subject to Royal
Decree, bp will remain operator of the block with a 40% interest.
Australasia
bp has activities in Australia and Eastern Indonesia.
Additional disclosures
In Australia bp is one of seven participants in the North West Shelf (NWS)
venture, which has been producing LNG, pipeline gas, condensate, LPG
and oil since the 1980s. Six partners (including bp) hold an equal 16.67%
interest in the gas infrastructure and an equal 15.78% interest in the gas
and condensate reserves, with a seventh partner owning the remaining
5.32%. bp also has a 16.67% interest in some of the NWS oil reserves
and related infrastructure. The NWS venture is currently the largest single
source supplier to the domestic market in Western Australia and one of
the largest LNG export projects in the region, with five LNG trains in
operation. bp’s net share of the capacity of NWS LNG trains 1-5 is
2.7 million tonnes of LNG per year.
bp is also one of five participants in the Browse LNG venture (operated by
Woodside) and holds a 17.33% interest.
• The Browse joint venture participants continue to progress the
development of Browse by connecting it via a 900km pipeline to the
NWS Venture's Karratha Gas Plant.
In Papua Barat, Eastern Indonesia, bp operates the Tangguh LNG plant
(bp 40.22%). The asset currently comprises 16 producing wells, two
offshore platforms, two pipelines and an LNG plant with two production
trains. It has a total capacity of 7.6 million tonnes of LNG per annum.
Tangguh supplies LNG to customers in Indonesia, Mexico, China, South
Korea, and Japan through a combination of long, medium and short-term
contracts.
The Tangguh expansion project comprises a third LNG processing train,
two offshore platforms, 10 new production wells, an expanded LNG
loading facility, and supporting infrastructure. The project will add 3.8
million tonnes per annum (mtpa) of production capacity to the existing
facility, bringing total plant capacity to 11.4mtpa. Due to COVID-19 and
the need to relocate personnel from the remote project, the start-up is
expected to be delayed to 2022.
In Abu Dhabi, bp holds a 10% interest in the ADNOC Onshore
concession. We also have a 10% equity shareholding in ADNOC LNG and
a 10% shareholding in the shipping company NGSCO. ADNOC LNG
supplied approximately 5.69 million tonnes of LNG (0.748bcfe/d
regasified) in 2020. Our interest in the ADNOC Onshore concession
expires at the end of 2054.
In 2016 bp signed an enhanced technical service agreement for south and
east Kuwait conventional oilfields, which includes the Burgan field, with
Kuwait Oil Company. Delivery of the 2019-2020 plan was above target
performance and implementation of the 2020-21 plan is underway.
In India we have a participating interest in two oil and gas PSAs (KG D6
33.33% and NEC25 33.33%), and one oil and gas block under a Revenue
Sharing Contract (KG-UDWHP-2018/1 40%), all operated by Reliance
Industries Limited (RIL). We also have a 50% stake in India Gas Solutions
Private Limited, a joint venture with RIL, for the sourcing and marketing of
gas in India.
• On 3 February, bp and RIL confirmed that they had completed the safe
cessation of production in a planned manner, from the D1 D3 field in
Block KG D6, off the east coast of India (bp 33.33%).
• During the year, impairment charges of $1,313 million were recognized
in respect of certain assets in India, primarily as a result of changes to
the group's long-term price assumptions.
• Also during the year, exploration write-offs of $333 million were
recognized in relation to certain assets in India following management's
re-assessment of expectations to extract value from certain exploration
prospects as a result of a review of the group's long-term strategic plan
and changes in the group's long-term price assumptions.
• On 18 December, bp and RIL announced the start of gas production
from R-Series, the first of the three projects in Block KG D6. The other
two projects (Satellites Cluster and MJ) are under development with
first gas production phased over 2021-2022.
In Indonesia bp successfully completed the purchase of a 30% non-
operated working interest in the Andaman II PSC from KrisEnergy in April.
Andaman II is a deep-water block covering 7,400 square kilometres area
in the North Sumatra basin, offshore from Aceh. Other interest holders
are Premier Oil (40%, operator) and Mubadala Petroleum (30%).
In Iraq bp holds a 47.6% working interest and is the lead contractor in the
Rumaila technical service contract in southern Iraq. The technical services
contract runs to December 2034. Rumaila is one of the world’s largest oil
fields, comprising five producing reservoirs. bp's activities have not been
materially impacted by the continued political instability and public
protests which have occurred in 2020.
In Russia in addition to its interest in Rosneft as detailed on page 320, bp
holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas) together
with Rosneft (50.1%) and a consortium comprising Oil India Limited,
Indian Oil Corporation Limited and Bharat PetroResources Limited
(29.9%). Taas is developing the Srednebotuobinskoye oil and gas
condensate field in East Siberia. Also with Rosneft, we hold a 49%
interest in Kharampurneftegaz LLC (Kharampur) to develop subsoil
resources within the Kharampurskoe and Festivalnoye licence areas in
Yamalo-Nenets. Rosneft (51%) and bp (49%) jointly own Yermak
Neftegaz LLC (Yermak), which conducts onshore exploration in the West
Siberian and Yenisei-Khatanga basins and currently holds six exploration
and production licences.
• During the year bp received $86 million of dividends net of withholding
taxes and $51 million of distribution of paid in capital from Taas.
« See Glossary
bp Annual Report and Form 20-F 2020
311
Oil and natural gas
Resource progression
bp manages its hydrocarbon resources in three major categories:
prospect inventory, contingent resources and reserves. When a discovery
is made, volumes usually transfer from the prospect inventory to the
contingent resources category. The contingent resources move through
various sub-categories as their technical and commercial maturity
increases through appraisal activity.
At the point of final investment decision, most proved reserves will be
categorized as proved undeveloped (PUD). Volumes will subsequently be
recategorized from PUD to proved developed (PD) as a consequence of
development activity. When part of a well’s proved reserves depends on
a later phase of activity, only that portion of proved reserves associated
with existing, available facilities and infrastructure moves to PD. The first
PD bookings will typically occur at the point of first oil or gas production.
Major development projects typically take one to five years from the time
of initial booking of PUD to the start of production. Changes to proved
reserves bookings may be made due to analysis of new or existing data
concerning production, reservoir performance, commercial factors and
additional reservoir development activity.
Volumes can also be added or removed from our portfolio through
acquisition or divestment of properties and projects. When we dispose of
an interest in a property or project, the volumes associated with our
adopted plan of development for which we have a final investment
decision will be removed from our proved reserves upon completion of
the transaction. When we acquire an interest in a property or project, the
volumes associated with the existing development and any committed
projects will be added to our proved reserves if bp has made a final
investment decision and they satisfy the SEC’s criteria for attribution of
proved status. Following the acquisition, additional volumes may be
progressed to proved reserves from non-proved reserves or contingent
resources.
Non-proved reserves and contingent resources in a field will only be
recategorized as proved reserves when all the criteria for attribution of
proved status have been met and the volumes are included in the
business plan and scheduled for development, typically within five years.
bp will only book proved reserves where development is scheduled to
commence after more than five years, if these proved reserves satisfy the
SEC’s criteria for attribution of proved status and bp management has
reasonable certainty that these proved reserves will be produced.
At the end of 2020 bp had material volumes of proved undeveloped
reserves held for more than five years in Russia, Trinidad, Gulf of Mexico,
Azerbaijan, Indonesia and the North Sea. These are part of ongoing
infrastructure-led development activities for which bp has a historical track
record of completing comparable projects in these countries. We have no
proved undeveloped reserves held for more than five years in our onshore
US developments.
In each case the volumes are being progressed as part of an adopted
development plan where there are physical limits to the development
timing such as infrastructure limitations, contractual limits including gas
delivery commitments, late life compression and the complex nature of
working in remote locations, or where there are significant commitments
on delivery to the relevant authority.
Over the past five years, bp has annually progressed a weighted average
17% (19% for 2019 five-year average) of our group proved undeveloped
reserves (including the impact of disposals and price acceleration effects
in PSAs) to proved developed reserves. This equates to a turnover time of
six years.
Proved reserves as estimated at the end of 2020 meet bp’s criteria for
project sanctioning and SEC tests for proved reserves. We have not
halted or changed our commitment to proceed with any material project
to which proved undeveloped reserves have been attributed.
entities). The major areas with progressed volumes in 2020 were Russia,
US, Egypt and Oman. Revisions of previous estimates for proved
undeveloped reserves are due to changes relating to field performance,
well results or changes in commercial conditions including price impacts.
The following tables describe the changes to our proved undeveloped
reserves position through the year for our subsidiaries and equity-
accounted entities and for our subsidiaries alone.
Subsidiaries and equity-accounted entities
Proved undeveloped reserves at 1 January 2020
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales
Total in year proved undeveloped reserves changes
Proved developed reserves reclassified as undeveloped
Progressed to proved developed reserves by
development activities (e.g. drilling/completion)
Proved undeveloped reserves at 31 December 2020
volumes in mmboea
8,152
298
133
436
442
(940)
369
247
(897)
7,871
Subsidiaries only
Proved undeveloped reserves at 1 January 2020
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales
Total in year proved undeveloped reserves changes
Proved developed reserves reclassified as undeveloped
Progressed to proved developed reserves by
development activities (e.g. drilling/completion)
Proved undeveloped reserves at 31 December 2020
volumes in mmboea
3,771
42
122
84
—
(8)
240
173
(512)
3,673
a Because of rounding, some totals may not agree exactly with the sum of their component parts.
bp bases its proved reserves estimates on the requirement of reasonable
certainty with rigorous technical and commercial assessments based on
conventional industry practice and regulatory requirements. bp only
applies technologies that have been field tested and have been
demonstrated to provide reasonably certain results with consistency and
repeatability in the formation being evaluated or in an analogous
formation. bp applies high-resolution seismic data for the identification of
reservoir extent and fluid contacts only where there is an overwhelming
track record of success in its local application. In certain cases bp uses
numerical simulation as part of a holistic assessment of recovery factor
for its fields, where these simulations have been field tested and have
been demonstrated to provide reasonably certain results with consistency
and repeatability in the formation being evaluated or in an analogous
formation. In certain deepwater fields bp has booked proved reserves
before production flow tests are conducted, in part because of the
significant safety, cost and environmental implications of conducting
these tests. The industry has made substantial technological
improvements in understanding, measuring and delineating reservoir
properties without the need for flow tests. To determine reasonable
certainty of commercial recovery, bp employs a general method of
reserves assessment that relies on the integration of three types of data:
• well data used to assess the local characteristics and conditions of
reservoirs and fluids
• field scale seismic data to allow the interpolation and extrapolation of
these characteristics outside the immediate area of the local well
control
• data from relevant analogous fields.
In 2020 we progressed 897 mmboe of proved undeveloped reserves (512
mmboe for our subsidiaries« alone) to proved developed reserves
through ongoing investment in our subsidiaries’ and equity-accounted
entities’ upstream development activities. Total development
expenditure, excluding midstream activities, was $11,041 million in 2020
($7,650 million for subsidiaries and $3,391 million for equity-accounted
Well data includes appraisal wells or sidetrack holes, full logging suites,
core data and fluid samples. bp considers the integration of this data in
certain cases to be superior to a flow test in providing understanding of
overall reservoir performance. The collection of data from logs, cores,
wireline formation testers, pressures and fluid samples calibrated to each
other and to the seismic data can allow reservoir properties to be
312
bp Annual Report and Form 20-F 2020
« See Glossary
determined over a greater volume than the localized volume of
investigation associated with a short-term flow test. There is a strong
track record of proved reserves recorded using these methods, validated
by actual production levels.
Regulation S-X. All reserves estimates involve some degree of
uncertainty. bp has filed D&M’s independent report on its reserves
estimates as an exhibit to this Annual Report on Form 20-F filed with the
SEC.
Additional disclosures
Governance
bp’s centrally controlled process for proved reserves estimation approval
forms part of a holistic and integrated system of internal control. It
consists of the following elements:
• Accountabilities of certain officers of the group to ensure that there is
review and approval of proved reserves bookings independent of the
operating business and that there are effective controls in the approval
process and verification that the proved reserves estimates and the
related financial impacts are reported in a timely manner.
• Capital allocation processes, whereby delegated authority is exercised
to commit to capital projects that are consistent with the delivery of the
group’s business plan. A formal review process exists to ensure that
both technical and commercial criteria are met prior to the commitment
of capital to projects.
• Group audit, whose role is to consider whether the group’s system of
internal control is adequately designed and operating effectively to
respond appropriately to the risks that are significant to bp.
• Approval hierarchy, whereby proved reserves changes above certain
threshold volumes require immediate review and all proved reserves
require annual central authorization and have scheduled periodic
reviews. The frequency of periodic review ensures that 100% of the bp
proved reserves base undergoes central review every three years.
bp’s vice president of segment reserves is the individual primarily
responsible for overseeing the preparation of the reserves estimate. He
has more than 27 years of diversified industry experience in reserves
estimation with the past 2 years managing the governance and
compliance. He is a past Chairman of the Society of Petroleum Engineers
(Russia & Caspian) and a member of the United Nations Economic
Commission for Europe Expert Group on Resource Management.
No specific portion of compensation bonuses for senior management is
directly related to proved reserves targets. Additions to proved reserves is
one of several indicators by which the performance of the Upstream
segment is assessed by the remuneration committee for the purposes of
determining compensation bonuses for the executive directors. Other
indicators include a number of financial and operational measures.
bp’s variable pay programme for the other senior managers in the
Upstream segment is based on individual performance contracts.
Individual performance contracts are based on agreed items from the
business performance plan, one of which, if chosen, could relate to
proved reserves.
Compliance
International Financial Reporting Standards (IFRS) do not provide specific
guidance on reserves disclosures. bp estimates proved reserves in
accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant
Compliance and Disclosure Interpretations (C&DI) and Staff Accounting
Bulletins as issued by the SEC staff.
By their nature, there is always risk involved in the ultimate development
and production of proved reserves including, but not limited to: final
regulatory approval; the installation of new or additional infrastructure, as
well as changes in oil and gas prices; changes in operating and
development costs; and the continued availability of additional
development capital. All the group’s proved reserves held in subsidiaries
and equity-accounted entities are estimated by the group’s petroleum
engineers or by independent petroleum engineering consulting firms and
then assured by the group’s petroleum engineers.
DeGolyer & MacNaughton (D&M), an independent petroleum engineering
consulting firm, has estimated the net proved crude oil, condensate,
natural gas liquids (NGLs) and natural gas reserves, as of 31 December
2020, of certain properties owned by Rosneft as part of our equity-
accounted proved reserves. The properties evaluated by D&M account for
100% of Rosneft’s net proved reserves as of 31 December 2020. The net
proved reserves estimates prepared by D&M were prepared in
accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of
Netherland, Sewell & Associates (NSAI), an independent petroleum
engineering consulting firm, has estimated the net proved crude oil,
condensate, natural gas liquids (NGLs) and natural gas reserves, as of
31 December 2020, of certain properties owned by bp in the US Lower
48. The properties evaluated by NSAI account for 100% of bp’s net
proved reserves in the US Lower 48 as of 31 December 2020. The net
proved reserves estimates prepared by NSAI were prepared in
accordance with the reserves definitions of Rule 4-10(a)(1)-(32) of
Regulation S-X. All reserves estimates involve some degree of
uncertainty. bp has filed NSAI’s independent report on its reserves
estimates as an exhibit to this Annual Report on Form 20-F filed with the
SEC.
Our proved reserves are associated with both concessions (tax and
royalty arrangements) and agreements where the group is exposed to the
upstream risks and rewards of ownership, but where our entitlement to
the hydrocarbons is calculated using a more complex formula, such as
with PSAs. In a concession, the consortium of which we are a part is
entitled to the proved reserves that can be produced over the licence
period, which may be the life of the field. In a PSA, we are entitled to
recover volumes that equate to costs incurred to develop and produce the
proved reserves and an agreed share of the remaining volumes or the
economic equivalent. As part of our entitlement is driven by the monetary
amount of costs to be recovered, price fluctuations will have an impact on
both production volumes and reserves.
We disclose our share of proved reserves held in equity-accounted
entities (joint ventures« and associates«), although we do not control
these entities or the assets held by such entities.
bp’s estimated net proved reserves and proved
reserves replacement
92% of our total proved reserves of subsidiaries at 31 December 2020
were held through joint operations« (91% in 2019), and 31% of the
proved reserves were held through such joint operations where we were
not the operator (28% in 2019).
Estimated net proved reserves of crude oil at
31 December 2020a b c
UK
USd
Rest of North Americad
South Americae
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
million barrels
Developed
Undeveloped
162
697
37
8
116
1,100
34
2,154
3,517
5,671
148
742
195
9
21
547
5
1,666
2,776
4,441
Total
309
1,438
232
16
137
1,647
38
3,819
6,293
10,112
Estimated net proved reserves of natural gas liquids at 31 December
2020a b
million barrels
UK
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
7
115
—
2
13
—
2
139
129
268
—
218
—
19
1
—
—
237
44
281
Total
7
333
—
21
14
—
2
376
172
549
313
« See Glossary
bp Annual Report and Form 20-F 2020
Estimated net proved reserves of liquids«
million barrels
Developed
Undeveloped
Subsidiariese
Equity-accounted entitiesf
Total
Estimated net proved reserves of natural gas at 31 December 2020a b
2,293
3,645
5,938
1,903
2,819
4,722
Total
4,196
6,465
10,661
billion cubic feet
Developed Undeveloped
UK
US
Rest of North America
South Americag
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entitiesh
Total
Estimated net proved reserves on an oil equivalent basisi
306
1,921
—
1,567
1,382
3,883
2,058
11,118
13,088
24,206
51
3,423
—
1,964
158
3,641
1,029
10,267
7,994
18,260
Total
358
5,344
—
3,531
1,541
7,524
3,087
21,385
21,082
42,467
million barrels of oil equivalent
Developed
Undeveloped
Total
7,883
10,100
17,982
Subsidiaries
Equity-accounted entities
Total
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the
4,210
5,902
10,112
3,673
4,198
7,871
royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently, and include non-controlling interests in
consolidated operations. We disclose our share of reserves held in joint ventures and associates
that are accounted for by the equity method although we do not control these entities or the
assets held by such entities.
b The 2020 marker prices used were Brent« $41.31/bbl (2019 $62.74/bbl and 2018 $71.43/bbl)
and Henry Hub« $1.94/mmBtu (2019 $2.58/mmBtu and 2018 $3.10/mmBtu).
c Includes condensate.
d All of the reserves in Canada are bitumen.
e Includes 11 million barrels of liquids in respect of the 30% non-controlling interest in BP Trinidad
and Tobago LLC.
f Includes 405 million barrels in respect of the non-controlling interest in Rosneft, including
19mmboe held through bp’s interests in Russia other than Rosneft.
g Includes 1,059 billion cubic feet of natural gas in respect of the 30% non-controlling interest in
BP Trinidad and Tobago LLC.
h Includes 1,640 billion cubic feet of natural gas in respect of the 10.01% non-controlling interest
in Rosneft including 614 billion cubic feet held through bp’s interests in Russia other than
Rosneft.
i Includes 264 million barrels of oil equivalent associated with Assets Held for Sale in Oman.
Because of rounding, some totals may not agree exactly with the sum of
their component parts.
Proved reserves replacement
Total hydrocarbon proved reserves at 31 December 2020, on an oil
equivalent basis including equity-accounted entities, decreased by 7%
compared with 31 December 2019. Natural gas represented about 41%
(47% for subsidiaries and 36% for equity-accounted entities) of these
reserves. The change includes a net decrease from acquisitions and
disposals of 1,069mmboe (decrease of 1,072mmboe within our
subsidiaries and increase of 3mmboe within our equity-accounted
entities). Acquisition and divestment activity occurred in our equity-
accounted entities in Russia, and divestment activity in our subsidiaries in
the US including Alaska.
The proved reserves replacement ratio« is the extent to which
production is replaced by proved reserves additions. This ratio is
expressed in oil equivalent terms and includes changes resulting from
revisions to previous estimates, improved recovery, and extensions and
discoveries. For 2020, the proved reserves replacement ratio excluding
acquisitions and disposals was 78% (67% in 2019 and 100% in 2018) for
subsidiaries and equity-accounted entities, 47% for subsidiaries alone and
127% for equity-accounted entities alone. There was a net decrease
(373mmboe) of reserves due to lower gas and oil prices within the US,
North Sea and Angola partly offset by increases related to price in some
of our PSAs in Iraq and Azerbaijan.
In 2020 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted to
1,006mmboe (380mmboe for subsidiaries and 626mmboe for equity-
accounted entities), through revisions to previous estimates including
price, improved recovery from, and extensions to, existing fields and
discoveries of new fields. The subsidiary additions were through
improved recovery from, and extensions to, existing fields and discoveries
of new fields where they represented a mixture of proved developed and
proved undeveloped reserves. Volumes added in 2020 principally resulted
from the application of conventional technologies and extensions of field
size by development drilling. The principal proved reserves additions in
our subsidiaries by region were in the US, Oman, Azerbaijan and Angola.
The principal reserves additions in our equity-accounted entities were in
Rosneft and Pan American Energy Group.
16% of our proved reserves are associated with PSAs. The countries in
which we produced under PSAs in 2020 were Algeria, Angola, Azerbaijan,
Egypt, India, Indonesia and Oman. In addition, the technical service
contract (TSC) governing our investment in the Rumaila field in Iraq
functions as a PSA.
The group holds no licences due to expire within the next three years that
would have a significant impact on bp’s reserves or production. bp holds
reserves classified as Assets held for sale in Oman.
For further information on our reserves see page 238.
314
bp Annual Report and Form 20-F 2020
« See Glossary
bp’s net production by country – crude oila and natural gas liquids
Subsidiaries
UKc d
Total Europe
Alaskac
Lower 48 onshorec
Gulf of Mexico deepwaterc
Total US
Canadae
Total Rest of North America
Total North America
Trinidad & Tobago
Total South America
Angola
Egyptc
Algeria
Total Africa
Abu Dhabi
Azerbaijan
Iraq
Oman
Total Rest of Asia
Total Asia
Australia
Eastern Indonesia
Total Australasia
Total subsidiaries
Equity-accounted entities (bp share)
Rosneftf (Russia, Venezuela)
Abu Dhabi
Additional disclosures
thousand barrels per day
bp net share of productionb
2020
2019
Crude oil
2018
2020
2019
Natural gas
liquids
2018
96
96
38
72
235
345
22
22
367
7
7
108
9
6
123
158
97
100
21
375
375
13
2
15
983
100
100
71
66
263
400
24
24
424
7
7
115
34
7
156
180
79
64
20
343
343
101
101
106
18
261
385
24
24
408
7
7
147
49
9
204
169
72
54
17
313
313
15
2
17
1,046
16
2
17
1,051
5
5
—
59
20
79
—
—
79
7
7
—
—
8
8
—
—
—
—
—
—
2
—
2
101
3
3
—
58
24
81
—
—
81
9
9
—
—
8
8
—
—
—
—
—
—
2
—
2
104
5
5
—
37
23
60
—
—
60
9
9
—
—
11
11
—
—
—
—
—
—
2
—
2
88
4
—
—
—
—
3
2
—
3
12
100
3
—
1
—
—
3
2
—
5
14
118
3
—
1
—
—
2
3
—
5
14
115
873
—
52
0
2
—
50
30
1
1,009
1,991
920
—
54
—
2
—
35
35
1
1,047
2,093
919
16
52
—
3
—
34
14
1
1,040
2,091
Argentina
Mexico
Bolivia
Egyptc
Norway
Russiac
Angola
Total equity-accounted entities
Total subsidiaries and equity-accounted entitiesg
a Includes condensate.
b Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
c In 2020, bp disposed of its Alaska interests and certain Lower 48 onshore interests in the US. In 2019, bp completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt
and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf of Mexico Santiago and Santa Cruz wells. In 2018, bp acquired various interests in the Permian Basin, Eagle Ford and
Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC
Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets
in the UK North Sea and US onshore assets.
d Volumes relate to six bp-operated fields within ETAP. bp has no interests in the remaining three ETAP fields, which are operated by Shell.
e All of the production from Canada in Subsidiaries is bitumen.
f Includes production in respect of the non-controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft.
g Includes 3 net mboe/d of NGLs from processing plants in which bp has an interest (2019 3mboe/d and 2018 3mboe/d).
Because of rounding, some totals may not agree exactly with the sum of their component parts.
« See Glossary
bp Annual Report and Form 20-F 2020
315
bp’s net production by country – natural gas
Subsidiaries
UKb
Total Europe
Lower 48 onshoreb
Gulf of Mexico deepwaterb
Alaskab
Total US
Canada
Total Rest of North America
Total North America
Trinidad & Tobago
Total South America
Egyptb
Algeria
Total Africa
Azerbaijan
India
Oman
Total Rest of Asia
Total Asia
Australia
Eastern Indonesia
Total Australasia
Total subsidiariesc
Equity-accounted entities (bp share)
Rosneftd (Russia, Canada, Egypt, Vietnam)
Argentina
Bolivia
Mexico
Norway
Russiab
Angola
Total equity-accounted entitiesc
Total subsidiaries and equity-accounted entities
million cubic feet per day
bp net share of productiona
2020
2019
2018
221
221
1,405
154
3
1,561
2
2
1,563
1,695
1,695
782
141
923
413
2
550
966
966
396
399
795
6,163
1,286
230
56
0
61
41
92
1,765
7,929
129
129
2,175
179
4
2,358
2
2
2,361
1,977
1,977
952
186
1,138
367
15
594
976
976
411
375
786
7,366
1,279
250
64
—
56
—
87
1,736
9,102
152
152
1,705
190
5
1,900
7
7
1,907
2,136
2,136
878
183
1,061
256
32
538
826
826
437
382
819
6,900
1,286
264
71
—
59
—
80
1,760
8,659
a Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b In 2020, bp disposed of its Alaska interests and certain Lower 48 onshore interests in the US. In 2019, bp completed the sale of its interest in the Gulf of Suez Petroleum Company (GUPCO) in Egypt
and certain US assets in Lower 48 onshore and disposed of its interests in the Gulf of Mexico Santiago and Santa Cruz wells. In 2018, bp acquired various interests in the Permian Basin, Eagle Ford and
Haynesville Shales in Lower 48 onshore as a result of the acquisition of BHP’s US unconventional assets, increased its interest in the Clair asset in the UK North Sea, and acquired an interest in LLC
Kharampurneftegaz in Russia, and in certain US offshore assets. It also disposed of its interests in the Greater Kuparuk Area in Alaska, the Magnus field in the UK North Sea, and in certain other assets
in the UK North Sea and US onshore assets.
c Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.
d Includes production in respect of the non-controlling interest in Rosneft, including production held through bp’s interests in Russia other than Rosneft.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
316
bp Annual Report and Form 20-F 2020
« See Glossary
The following tables provide additional data and disclosures in relation to our oil and gas operations.
Average sales price per unit of production (realizations«)a
Additional disclosures
Europe
UK
Rest of
Europe
North
America
US
Rest of
North
America
South
America
Africa
Asia
Russiab
Rest of
Asia
$ per unit of production
Total
group
average
Australasia
42.70
25.31
3.13
65.44
29.58
4.01
71.28
31.63
7.71
—
—
—
—
—
—
—
—
—
38.14
10.22
1.30
26.70
—
1.70
42.27
16.49
1.86
41.60
25.39
3.89
59.19
14.67
1.93
40.92
—
0.75
63.30
25.86
2.78
63.75
31.89
4.59
67.11
25.81
2.43
33.57
—
0.83
69.17
35.74
3.08
68.81
39.14
4.82
—
—
—
—
—
—
—
—
—
37.76
—
3.91
33.21
24.73
4.66
64.39
—
3.99
59.65
38.11
6.86
70.80
—
3.85
67.54
52.14
7.97
—
—
—
—
—
—
—
—
—
40.00
—
3.76
64.75
—
5.01
70.24
—
7.93
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
40.41
15.93
2.88
56.85
18.14
3.98
62.35
—
4.36
—
—
—
—
—
—
—
—
—
35.10
N/A
1.51
56.52
N/A
1.83
—
—
—
—
—
—
62.51
N/A
1.70
39.49
—
—
—
—
—
—
—
—
—
—
—
38.46
12.91
2.75
61.56
18.23
3.39
67.81
29.42
3.92
35.94
15.93
1.85
56.96
18.14
2.38
62.29
—
2.50
Subsidiaries
2020
Crude oilc
Natural gas liquids
Gas
2019
Crude oilc
Natural gas liquids
Gas
2018
Crude oilc
Natural gas liquids
Gas
Equity-accounted entitiesd
2020
Crude oilc
Natural gas liquidse
Gas
2019
Crude oilc
Natural gas liquidse
Gas
2018
Crude oilc
Natural gas liquidse
Gas
Average production cost per unit of productionf
Europe
UK
Rest of
Europe
North
America
US
Rest of
North
America
South
America
Africa
Asia
$ per unit of production
Total
group
average
Australasia
Russiac
Rest of
Asia
12.49
13.22
13.76
—
—
—
8.11
8.46
9.63
12.46
13.36
13.10
3.76
3.36
3.08
7.71
7.95
7.31
—
—
—
4.41
5.15
5.72
2.02
2.33
2.35
6.39
6.84
7.15
Subsidiaries
2020
2019
2018
Equity-accounted entities
2020
2019
2018
a Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses, except in the case of Russia.
b An amendment has been made to 2019 and 2018 to align with the disclosures for oil and natural gas exploration and production activities.
c Includes condensate.
d In certain countries it is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets
12.71
11.50
10.61
8.14
12.51
12.15
3.54
3.45
3.37
—
—
5.92
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4.55
4.50
4.38
at discounted prices.
e Natural gas liquids for Russia are included in crude oil.
f Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
« See Glossary
bp Annual Report and Form 20-F 2020
317
Additional information for Downstream
Refinery throughputsa b
Retail sitesa
US
Europe
Rest of the world
Total
2020
693
742
192
1,627
2019
737
787
225
1,749
Refining availability«
96.0
94.9
a This does not include bp’s interest in Pan American Energy Group.
b Refinery throughputs reflect crude oil and other feedstock volumes.
Sales volume
Marketing salesa
Trading/supply salesb
Total refined product sales
Crude oilc
Total
2020
2,275
3,026
5,301
2,397
7,698
2019
2,727
3,268
5,995
2,713
8,708
thousand
barrels per
day
2018
703
781
241
1,725
%
95.0
thousand
barrels per
day
2018
2,736
3,194
5,930
2,624
8,554
a Marketing sales include branded and unbranded sales of refined fuel products and lubricants to
business-to-business and business-to-consumer customers, including service station dealers,
jobbers, airlines, small and large resellers such as hypermarkets, and the military.
b Trading/supply sales are fuel sales to large unbranded resellers and other oil companies.
c Crude oil sales relate to transactions executed by our integrated supply and trading function,
primarily for optimizing crude oil supplies to our refineries and in other trading. 2020 includes 44
thousand barrels per day relating to revenues reported by the Upstream segment.
Sales volumes reported in the table above are for those transactions that
are reported as gross sales in the group income statement. From 2021,
certain sales and purchase transactions that have previously been
reported gross in the group income statement will be reported on a net
basis in the income statement. The volumes for 2020 transactions that
would have been subject to potential netting in the income statement but
are presented gross in this table are approximately 2,063 thousand barrels
a day of crude oil, 2,613 thousand barrels a day of trading/supply sales,
and 126 thousand barrels a day of marketing sales.
US
Europe
Rest of the world
Total
Number of
bp-branded
retail sites
2018
7,200
8,200
3,300
2020
7,300
8,200
4,800
2019
7,200
8,200
3,500
20,300
18,900
18,700
a Reported to the nearest 100. Includes sites operated by dealers, jobbers, franchisees, brand
licensees or JV partners, under the bp brand. These may move to and from the bp brand as their
fuel supply agreement or brand licence agreement expires and are renegotiated in the normal
course of business. Retail sites are primarily branded bp, ARCO, Amoco, Aral and Thorntons, and
also include sites in India through our Jio-bp JV.
Reconciliation of RC profit before interest and tax to
gross margin for convenience, retail fuels and
electrification
RC profit before interest and tax for
Downstream
Net (favourable) adverse impact of non-
operating items« and fair value accounting
effects«
Underlying RC profit before interest and tax
for Downstream
Subtract underlying RC profit (loss) for
petrochemicals, refining and trading, and
lubricants
Add back:
2020
3.4
$ billion
2019
6.5
(0.3)
(0.1)
3.1
6.4
1.0
3.9
Fuels (excluding refining and trading)
depreciation, depletion and amortization
1.0
1.0
Fuels (excluding refining and trading)
production and manufacturing,
distribution and administration
expenses and adjusted for aviation,
B2B and midstream gross margin
Adjusted for earnings from equity-
accounted entities in fuels (excluding
refining and trading)
Gross margin for convenience, retail fuels
and electrification«
Of which:
Convenience gross margin
Retail fuels gross margin
Electrification gross margin
1.9
1.8
(0.2)
(0.3)
4.8
1.3
3.5
0.0
5.0
1.2
3.7
0.0
318
bp Annual Report and Form 20-F 2020
« See Glossary
Refinery capacity
The following tablea summarizes bp group’s interests in refineries and average daily crude distillation capacities as at 31 December 2020.
Additional disclosures
Fuels value chain
US
US North West
US East of Rockies
Europe
Rhine
Iberia
Rest of world
Australia
New Zealand
Southern Africa
Country
Refinery
US
Cherry Point
Whiting
Toledo
Germany
Netherlands
Spain
Gelsenkirchen
Lingen
Rotterdam
Castellón
Australia
New Zealand
South Africa
Kwinanad
Whangareief
Durbane
Crude distillation capacitiesb
Group interestc
(%)
BP share
thousand barrels
per day
100
100
50
100
100
100
100
100
10.1
50
251
440
80
771
265
97
390
110
862
152
34
90
276
1,909
Total bp share of capacity at 31 December 2020
a This does not include bp’s interest in Pan American Energy Group.
b Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period under normal operational conditions.
c bp share of equity, which is not the same as bp share of processing entitlements.
d In the fourth quarter 2020, we announced plans to cease fuel production at our Kwinana Refinery and convert it to an import terminal.
e Indicates refineries not operated by bp.
f Reflects bp share of processing entitlement, which is not the same as bp share of equity.
« See Glossary
bp Annual Report and Form 20-F 2020
319
presented its public statement regarding human rights and the
Declaration on Human Rights for interacting with suppliers of goods,
works and services.
In February 2021,Rosneft and bp signed a Strategic Collaboration
Agreement focused on supporting carbon management and sustainability
activities of both companies.
The agreement builds on bp’s longstanding strategic partnership with
Rosneft and will explore opportunities for new investment and
collaboration in Russia across several key focus areas:
• Developing industry methodologies and standards on carbon
management, including methane reduction initiatives and energy
efficiency applications.
• Evaluating new projects in renewables, carbon capture and hydrogen.
• Assessing opportunities in the downstream including advanced fuels,
natural forest sinks and carbon offset credits.
• Sustainable development and social investment, including biodiversity.
Additional information for Rosneft
About Rosneft
Rosneft is the largest oil company in Russia, with a strong portfolio of
current and future opportunities. Russia has one of the largest and
lowest-cost hydrocarbon resource bases in the world and its resources
play an important role in long-term energy supply to the global economy.
Rosneft is one of the largest publicly traded oil companies in the world
based on hydrocarbon production volume. And it has a major resource
base of hydrocarbons onshore and offshore, with assets in all of Russia’s
key hydrocarbon regions and abroad. bp's share of Rosneft hydrocarbon
production in 2020 was 1,098mboe/d, compared with 1,144mboe/d in
2019.
Rosneft is a member of the Methane Guiding Principles initiative that
aims to reduce methane emissions along the natural gas value chain. It
reaffirmed its commitment to the 17 UN Sustainable Development Goals
and the core principles of the UN Global Compact.
Rosneft is the leading Russian refining company based on throughput. It
owns and operates 13 refineries in Russia and holds stakes in three
refineries in Germany, one in India and one in Belarus. Rosneft refinery
throughput in 2020 was 2,103mb/d, compared with 2,236mb/d in 2019.
Downstream operations include jet fuel, bunkering, bitumen and
lubricants. Rosneft also owns and operates over 3,055 retail service
stations in Russia and abroad. These includes Rosneft-branded sites, as
well as bp-branded sites operating under a licensing agreement.
Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz), which is
wholly owned by the Russian government. At 31 December 2020,
Rosneftegaz held 40.4% (2019: 50% plus one share) of the voting share
capital of Rosneft.
2020 summary
bp remains committed to our strategic investment in Rosneft, while
complying with all relevant sanctions.
bp’s two nominees, Bernard Looney and Bob Dudley, were elected to
Rosneft’s board at Rosneft's annual general meeting (AGM) in June. Bob
Dudley is a chairman of the Rosneft board’s Strategy and Sustainable
Development Committee. At the AGM, shareholders also approved a
resolution to pay a dividend. bp received a payment of $480 million, after
the deduction of withholding tax, in July.
On 30 April, Rosneft completed a transaction to transfer all of its interest
and cease participation in its Venezuelan businesses to a company owned
by the government of the Russian Federation. In consideration, it received
shares equal to a 9.6% share of its own equity. The shares are held by a
100% subsidiary of Rosneft and accounted for as treasury shares.
Rosneft also has an approved programme of share buybacks under which
shares are being repurchased. Those shares are also accounted for as
treasury shares.
bp retains 19.75% of the voting rights at meetings of Rosneft
shareholders and continues to be entitled to dividends based on that
shareholding. bp’s economic interest as of 31 December 2020, however,
has increased to 22.03% as a result of its indirect interest in the shares
held by the subsidiaries of Rosneft. bp’s share of profit or loss of Rosneft
reflects its economic interest.
On 14 December 2020, Rosneft announced the sale of a 49% stake in
Krasgeonats to Equinor for approximately $550 million. Krasgeonats owns
12 licences for exploration and production in Eastern Siberia, including the
recently launched North-Danilovskoye field.
On 28 December, Rosneft announced completion of the acquisition of
100% stakes in JSC Taimyrneftegaz and LLC Taimyrburservis, and the
sale of a 10% interest in LLC Vostok Oil to Trafigura for Euro 7 billion.
In December, Rosneft announced that it has developed a 2035 Carbon
Management Plan, a long-term framework for its development in the
context of transitioning to a low carbon economy, including management
of climate risks and identification of opportunities related to future energy
demand.
2020 marked the 10th anniversary of Rosneft’s participation in UN Global
Compact, the world’s largest sustainability initiative. In 2020, Rosneft
320
bp Annual Report and Form 20-F 2020
« See Glossary
Environmental expenditure
Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental
remediation provision
Increase (decrease) in
2020
531
241
29
2019
511
468
23
$ million
2018
501
449
31
297
272
428
decommissioning provision
(686)
1,045
137
Operating and capital expenditure on the prevention, control, treatment or
elimination of air and water emissions and solid waste is often not
incurred as a separately identifiable transaction. Instead, it forms part of a
larger transaction that includes, for example, normal operations and
maintenance expenditure. The figures for environmental operating and
capital expenditure in the table are therefore estimates, based on the
definitions and guidelines of the American Petroleum Institute.
Environmental operating expenditure of $531 million in 2020 (2019 $511
million) showed an overall increase of 4%, with increases in BP Products
and Shipping expenditure largely balanced out by a reduction in
expenditure for BPX Energy.
Environmental capital expenditure of $241 million in 2020 was
significantly down (2019 $468 million) largely due to decreased
expenditure in the BPX Energy and BP Products North America business.
Clean-up costs were $29 million in 2020 (2019 $23 million) representing
oil spill clean-up costs and other associated remediation and disposal
costs. The increase compared to 2019 results largely from increased
expenditure in three businesses, namely BP Pipelines (North America),
Alaska and Remediation Management.
In addition to operating and capital expenditure, we also establish
provisions for future environmental remediation work. Expenditure against
such provisions normally occurs in subsequent periods and is not included
in environmental operating expenditure reported for such periods.
Provisions for environmental remediation are made when a clean-up is
probable and the amount of the obligation can be reliably estimated.
Generally, this coincides with the commitment to a formal plan of action
or, if earlier, on divestment or on closure of inactive sites.
The extent and cost of future environmental restoration, remediation and
abatement programmes are inherently difficult to estimate. They often
depend on the extent of contamination, and the associated impact and
timing of the corrective actions required, technological feasibility and bp’s
share of liability. Though the costs of future programmes could be
significant and may be material to the results of operations in the period in
which they are recognized, it is not expected that such costs will be
material to the group’s overall results of operations or financial position.
Additions to our environmental remediation provision was similar to prior
years and also reflects scope reassessments of the remediation plans of a
number of our sites in the US. The charge for environmental remediation
provisions in 2020 included $8 million in respect of provisions for new
sites (2019 $9 million and 2018 $8 million).
In addition, we make provisions on installation of our oil and gas
producing assets and related pipelines to meet the cost of eventual
decommissioning. On installation of an oil or natural gas production
facility, a provision is established that represents the discounted value of
the expected future cost of decommissioning the asset.
In 2020, the net decrease in the decommissioning provision was due to a
change in the discount rate and a change in cost estimate assumptions.
We undertake periodic reviews of existing provisions. These reviews take
account of revised cost assumptions, changes in decommissioning
requirements and any technological developments.
Provisions for environmental remediation and decommissioning are
usually established on a discounted basis, as required by IAS 37
‘Provisions, Contingent Liabilities and Contingent Assets’.
Further details of decommissioning and environmental provisions appear
in Financial statements – Note 23.
Additional disclosures
Regulation of the group’s business
Our businesses and operations are subject to the laws and regulations
applicable in each country, state or other regional or local area in which
they occur. These cover virtually all aspects of bp’s activities and include
matters such as licence acquisition, production rates, royalties,
environmental, health and safety protection, fuel specifications and
transportation, trading, pricing, anti-trust, export, taxes, and foreign
exchange.
Oil and gas contractual and regulatory framework
The terms and conditions of the leases, licences and contracts under
which our upstream oil and gas interests are held vary from country
to country. These leases, licences and contracts are generally granted
by or entered into with a government entity or state-owned or
controlled company and are sometimes entered into with private
property owners. Arrangements with governmental or state entities
usually take the form of licences or production-sharing
agreements« (PSAs), although arrangements with private entities
and the US government entities are usually by lease.
Licences (or concessions) give the holder the right to explore for,
develop and produce a commercial discovery. Under a licence, the
holder bears the risk of exploration, development and production
activities and provides the financing for these operations. In principle,
the licence holder is entitled to all production, minus any royalties that
are payable in kind. A licence holder is generally required to pay
production taxes or royalties, which may be in cash or in kind.
In certain countries, separate licences are required for exploration and
production activities, and in some cases production licences are
limited to only a portion of the area covered by the original exploration
licence.
PSAs entered into with a government entity or state-owned or
controlled company generally require bp (alone or with other
contracting companies) to provide all the financing and bear the risk
of exploration and production activities in exchange for a share of the
production remaining after royalties, if any. Less typically, bp may
explore for, develop and produce hydrocarbons under a service
agreement with the host entity in exchange for reimbursement of
costs and/or a fee paid in cash rather than production.
bp frequently conducts its exploration and production activities in joint
arrangements« or co-ownership arrangements with other
international oil companies, state-owned or controlled companies
and/or private companies. Conventionally, all costs, benefits, rights,
obligations, liabilities and risks incurred in carrying out joint
arrangement or co-ownership operations under a lease, licence or
PSA are shared among the joint arrangement or co-owning parties
according to agreed ownership interests among them. To the extent
that any liabilities arise, whether to governments or third parties, or
as between the joint arrangement parties or co-owners themselves,
each joint arrangement party or co-owner will generally be liable to
meet these in proportion to its ownership interest. In many upstream
operations, a party (known as the operator) will be appointed
(pursuant to a joint operating agreement) to carry out day to-day
operations on behalf of the joint arrangement or co-ownership. The
operator is typically one of the joint arrangement parties or a co-
owner and will carry out its duties either through its own staff, or by
contracting out various elements to third-party contractors or service
providers. bp acts as operator on behalf of joint arrangements and co-
ownerships in a number of countries.
Frequently, work (including drilling and related activities) will be
contracted out to third-party service providers. The relevant contract
will specify the work, the remuneration, and typically the risk
allocation between the parties. Depending on the service to be
provided, the contract may also contain provisions allocating risks and
liabilities associated with pollution and environmental damage,
damage to a well or hydrocarbon reservoirs and for claims from third
parties or other losses. The allocation of those risks vary among
contracts and are determined through negotiation between the
parties.
« See Glossary
bp Annual Report and Form 20-F 2020
321
In general, bp incurs income tax on income generated from
production activities (whether under a licence or PSA). In addition,
depending on the area, bp’s production activities may be subject to a
range of other taxes, levies and assessments, including special
petroleum taxes and revenue taxes. The taxes imposed on oil and
gas production profits and activities may be substantially higher than
those imposed on other activities, for example in Abu Dhabi, Angola,
Egypt, Norway, the UK, the US, Russia and Trinidad & Tobago.
Sustainable finance
On 12 July 2020, elements of Regulation (EU) 2020/852 on the
establishment of a framework to facilitate sustainable investment
(Taxonomy Regulation) entered into force and form part of UK law
pursuant to the European Union (Withdrawal) Act of 2018. The
Taxonomy Regulation establishes a classification system for determining
whether an economic activity is environmentally sustainable for the
purposes of guiding investors in financial products which are marketed as
promoting environmental objectives. Although the UK government has
expressed its intention to retain the overall taxonomy framework and
objectives as set forth in the Taxonomy Regulation, it is not yet clear to
what extent UK law will align with elements of the Taxonomy Regulation
which were not in effect as of the end of the Brexit transition period on
31 December 2020. bp may in the future be required to comply with the
Taxonomy Regulation or any parallel or similar legislation which may come
into force in the UK.
Greenhouse gas regulation
In December 2015, nearly 200 nations at the United Nations climate
change conference in Paris (COP21) agreed the Paris Agreement
which aims to hold the increase in the global average temperature to
well below 2°C above pre-industrial levels and to pursue efforts to
limit the temperature increase to 1.5°C above pre-industrial levels.
Signatories aim to reach global peaking of greenhouse gas (GHG)
emissions as soon as possible and to undertake rapid reductions
thereafter, so as to achieve a balance between human caused
emissions and removals by sinks of GHGs in the second half of this
century. The Paris Agreement commits all signatories to submit
Nationally Determined Contributions (NDCs) (i.e. pledges or plans of
climate action) and pursue domestic measures aimed at achieving the
objectives of their NDCs. Signatories are required to submit revised
NDCs every five years, and the revised NDC’s are expected to be
more ambitious with each revision. Global assessments of progress
will occur every five years, starting in 2023.
Agreement of rules which could enable international carbon trading to
assist in meeting NDCs, has been deferred to COP26 which is
expected to take place in Glasgow, Scotland in November 2021.
More stringent national and regional measures relating to the
transition to a lower carbon economy, such as the UK's 2050 net zero
carbon emissions commitment, can be expected in the future. These
measures could increase bp’s production costs for certain products,
increase compliance and litigation costs, increase demand for
competing energy alternatives or products with lower-carbon
intensity, and affect the sales and specifications of many of bp’s
products. Further, such measures could lead to constraints on
production and supply and access to new reserves, particularly due to
the long term nature of many of bp’s projects. Certain current and
announced GHG measures and developments potentially affecting
bp’s businesses in various markets in which bp operates are
summarized below. For information on steps that bp is taking in
relation to climate change issues and for details of bp’s GHG
reporting, see Sustainability – Net zero aims on page 49.
United States
In the US, bp's operations are affected by GHG regulation in a
number of ways. The federal Clean Air Act (CAA), for example,
regulates air emissions, permitting, fuel specifications and other
aspects of our production, refining, distribution and marketing
activities.
Environmental Protection Agency (EPA) regulations aimed at limiting
methane emissions from new and modified sources in the oil and natural
gas sector in the US by 40-45% from 2012 levels by 2025 were the
subject of an August 2020, EPA final ‘policy rule’ intended to significantly
revise that regulation. This rule is the subject of litigation in the D.C.
Circuit. In addition, the Bureau of Land Management (BLM) in 2018
issued a new waste prevention rule which rescinded the prior 2017 rule
regarding methane regulation on federal lands. While litigation around
both rules is expected to continue, the Biden administration has taken
executive action with respect to Federal regulations promulgated during
the Trump administration relating to climate change, including a review of
both of these rules. Other EPA GHG regulations which may affect
electricity generation practices and prices and have an impact on the
market for fuels used to generate electricity and on renewable energy
installations are in flux due to changes in approach between presidential
administrations, as well as lawsuits challenging proposed regulations. In
2019, the EPA issued the final Affordable Clean Energy (ACE) Rule, which
is intended to address GHG emissions from certain existing sources in
the electricity sector, and which is intended to replace the Obama
administration’s Clean Power Plan (CPP). A number of lawsuits have been
filed regarding the legality of the ACE Rule and the repeal of the CPP
regulations, and on 19 January 2021, the DC Circuit struck down the ACE
rule in its entirety. The Biden administration may develop new regulations
that more closely mirror the CPP.
The Energy Policy Act of 2005 and the Energy Independence and
Security Act of 2007 impose the Renewable Fuel Standard (RFS),
requiring transportation fuel sold in the United States to contain a
minimum volume of renewable fuels. Certain state initiatives impose
lower GHG emissions thresholds for transportation fuels (e.g., in
California and Oregon). In 2020, EPA changed its approach to Small
Refinery Exemptions based on court activity. EPA is behind schedule
in setting RFS requirements for 2021 and we expect the
administration to begin the process of setting 2023 and beyond
volumes in 2021 as well.
The GHG mandatory reporting rule, requires operators of certain
facilities and producers and importers/exporters of petroleum
products to file annual GHG emissions reports with the EPA
quantifying direct emissions from affected facilities, as well as
volumes of petroleum products, certain natural gas liquids and GHG
products and notional GHG emissions as if these products were fully
combusted.
A number of states, municipalities and regional organizations have
responded to current and proposed federal changes easing
environmental regulation with separate initiatives that affect our US
operations. For example, the California cap and trade programme
started in January 2012 and expanded to cover emissions from
transportation fuels in 2015. The State of Washington has adopted a
carbon cap rule although the state’s Supreme Court has modified the
rule to exclude coverage of sales and distribution of petroleum fuels.
We expect a number of states to advance economy-wide and
transport/fuels specific regulations in 2021.
Our US businesses are subject to increased GHG and other
environmental requirements and regulatory uncertainty, including that
the Biden or any future US administrations could revise or revoke
current or prior administration programs, as well as increased
expenditures in having to comply with numerous diverse and non-
uniform regulatory initiatives at the state and local level.
US fuel markets are affected by EPA regulation of light, medium and
heavy duty vehicle emissions (both fuel economy and tailpipe
standards) as well as for non-road engines and vehicles and certain
large GHG stationary emission sources. California also imposes Low
Emission Vehicle (LEV) and Zero Emission Vehicle (ZEV) standards on
vehicle manufacturers and a number of other states, as allowed by
CAA authority, have adopted standards identical to California’s
standards. These regulations may impact bp’s product mix and
demand for particular products in those states. In August 2020,
California also entered into agreements with several carmakers to
meet more demanding emissions standards in California.
In 2019 the Trump administration issued the Safer Affordable Fuel-
Efficient Vehicles rule rolling back the Obama administration’s fuel
economy and tailpipe carbon dioxide emissions standards for
passenger cars and light trucks covering model years (MY) 2021
through 2026 by locking in the 2020 standards until 2026. It has also
proposed eliminating the waiver allowing California to set its own LEV
and ZEV standards and for other states to adopt those standards.
Litigation challenging these regulations is ongoing although the Biden
322
bp Annual Report and Form 20-F 2020
« See Glossary
administration is expected to restore the California waiver and
commence rulemaking to reinstate the stricter fuel economy and
tailpipe carbon dioxide emissions standards.
In January 2020, EPA solicited on a proposed rulemaking known as
the Cleaner Trucks Initiative. The rule would, among other things,
establish new emission standards for oxides of nitrogen (NOx) and
other pollutants for highway heavy-duty engines and the Biden
administration is expected to modify and continue this proposed
rulemaking. California has also adopted a “Heavy-Duty Low NOx
Omnibus Regulation” which will require manufacturers to comply
with stricter emissions standards. The rule is being phased in, with
the first phase effective in 2024. bp continues to monitor these rules
for implications for fuels.
European Union
• The EU and its member states have adopted various measures seeking
to reduce GHG emissions and encourage renewables. A set of
regulatory measures adopted by the EU include: a collective national
reduction target for emissions not covered by the EU Emissions
Trading System (EU ETS) Directive; binding national renewable energy
targets (including targets in the transport sector) under the Renewable
Energy Directive; and a legal framework to promote carbon capture and
storage.
• In 2014, EU leaders adopted a climate and energy framework setting
targets for the year 2030 including at least 40% reductions in GHG
emissions from 1990 levels and in December 2020 the Council agreed
an increase to a 55% reductions target from 1990 levels which is
pending before the European Parliament.
• In December 2019, the European Commission proposed an ambitious
‘European Green Deal’. These proposals, which require formal approval
by EU Member States to be adopted and include climate neutrality and
increased GHG reduction targets, tightening of the emissions caps in
the EU ETS, extending the EU ETS to include the maritime sector and
reducing allowances allocated to airlines, implement a carbon border
tax adjustment and harmonise energy taxation across the EU Member
States.
• In October 2020 the European Commission presented an EU strategy
to reduce methane emissions. The strategy sets out measures to cut
methane emissions in Europe and internationally. It presents legislative
and non-legislative actions in the energy, agriculture and waste sectors,
which account for around 95% of methane emissions associated with
human activity worldwide.
• European regulations also establish passenger car performance
standards for CO2 tailpipe emissions (European Regulation (EC) No
443/2009). By 2021, the European passenger fleet emissions target for
new vehicles will be 95 grams of CO2 per kilometre. This target will be
achieved by manufacturing fuel efficient vehicles and vehicles using
alternative, low carbon fuels such as hydrogen and electricity.
• In 2019, the European Parliament and the Council adopted Regulation
(EU) 2019/631 setting CO2 emission performance standards for new
passenger cars and for new light commercial vehicles (vans) in the EU
for the period after 2020. From a 2021 baseline, it requires EU fleet-
wide reductions of 15% by 2025 and 37.5% by 2030 for passenger
cars, and 15% by 2025 and 31% by 2030 for new light commercial
vehicles.
• The EU Fuel Quality Directive affects our production and marketing of
transport fuels including mandating reductions in the life cycle GHG
emissions per unit of energy and tighter environmental fuel quality
standards for petrol and diesel.
• Germany is expected to launch a national emissions trading system in
2021 for transport and heating fuels. Impacted fuel suppliers in
Germany will pay a fixed price for emissions certificates of EUR 25 per
tonne CO2 in 2021 rising to EUR 55 per tonne by 2025. In 2026,
emissions certificates will be auctioned but with prices limited between
EUR 55 and EUR 65 per tonne CO2 emitted. A review of the system is
expected to take place in 2025 to determine the position beyond 2026.
Other
• In December 2020 the UK Government announced a targeted reduction
in the UK’s GHG emissions of at least 68% by 2030, compared to 1990
levels. The UK also announced an emissions trading system from 1
Additional disclosures
January 2021 onwards which would include the same installations in
the UK that were previously subject to the EU ETS.
• China is operating emission trading pilot programmes in five cities and
three provinces. One of bp's subsidiaries« and one of bp’s joint
venture« companies in China are participating in these schemes. China
launched its national emissions trading market (National ETS), initially
covering the power sector only, politically in 2017. On 31 December
2020, China promulgated the national regulation on National ETS which
became effective on 1 February 2021, when the National ETS was
officially launched.
• China has also adopted more stringent vehicle tailpipe emission
standards and vehicle efficiency standards to address air pollution and
GHG emissions. These standards will have an impact on transportation
fuel product mix and overall demand. In addition, China has also
introduced a mandate for sales of new energy vehicles (NEVs)
commencing in 2020. This has been accelerating NEV penetration into
the light vehicle sector and impact light fuel demand.
Other environmental regulation
In addition to GHG regulations including current and proposed fuel
and product specifications and emission controls (including control of
vehicle emissions) referred to above, climate change programmes
and regulation of unconventional oil and gas extraction under a
number of environmental laws may have a significant effect on the
production, sale and profitability of many of bp’s products.
Environmental laws also require bp to remediate and restore areas
affected by the release of hazardous substances or hydrocarbons
associated with our operations or properties. These laws may apply
to sites that bp currently owns or operates, sites that it previously
owned or operated, or sites used for the disposal of its and other
parties’ waste. See Financial Statements – Note 23 for information on
provisions for environmental restoration and remediation.
A number of pending or anticipated governmental proceedings
against certain bp group companies under environmental laws could
result in monetary or other sanctions. Group companies are also
subject to environmental claims for personal injury and property
damage alleging the release of, or exposure to, hazardous
substances. The costs associated with future environmental
remediation obligations, governmental proceedings and claims could
be significant and may be material to the results of operations in the
period in which they are recognized. We cannot accurately predict the
effects of future developments, such as stricter environmental laws
and regulations or enforcement policies, or future events at our
facilities, on the group, and there can be no assurance that material
liabilities and costs will not be incurred in the future. For a discussion
of the group’s environmental expenditure, see page 321 and for a
discussion of legal proceedings, see page 226.
Significant legislation and regulation in the US and the EU affecting
our businesses and profitability, in addition to those referred to
above, include the following:
United States
• The Clean Water Act regulates wastewater and other effluent
discharges from bp’s facilities, and bp is required to obtain discharge
permits, install control equipment and implement operational controls
and preventative measures.
• The Resource Conservation and Recovery Act regulates the generation,
storage, transportation and disposal of wastes associated with our
operations and can require corrective action at locations where such
wastes have been disposed of or released. bp has incurred, or is likely
to incur, liability under RCRA or similar state laws in connection with
sites bp operates or previously operated.
• The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) can, in certain circumstances, impose the entire
cost of investigation and remediation on a party who owned or
operated a site contaminated with a hazardous substance, or who
arranged for disposal of a hazardous substance at a site. bp has
incurred, or is likely to incur, liability under CERCLA or similar state
laws, including costs attributed to insolvent or unidentified parties. bp is
also subject to claims for remediation costs and natural resource
damages under CERCLA and other federal and state laws.
« See Glossary
bp Annual Report and Form 20-F 2020
323
• The Emergency Planning and Community Right-to-Know Act requires
reporting on the storage, use and releases of certain quantities of listed
hazardous substances to designated government agencies.
• The Toxic Substances Control Act (TSCA) regulates bp’s manufacture,
import, export, sale and use of chemical substances and products. In
addition, EPA has revised processes and procedures for prioritisation of
existing chemicals for risk evaluation, assessment and management.
Agency actions and announcements are monitored regularly to identify
developments with potential impacts on chemical substances
important to bp products and operations. Thus far, bp has identified two
substances for specific ongoing monitoring of developments and
impacts.
• The Occupational Safety and Health Act imposes workplace safety and
health requirements on bp operations along with significant process
safety management obligations, requiring continuous evaluation and
improvement of operational practices to enhance safety and reduce
workplace emissions at gas processing, refining and other regulated
facilities.
• The Oil Pollution Act 1990 (OPA) imposes operational requirements,
liability standards and other obligations governing the transportation of
petroleum products in US waters. States may impose additional
obligations. Alaska and the West Coast states currently have the most
demanding state requirements.
• The Outer Continental Shelf Land Act, the Mineral Leasing Act and
other statutes give the Department of Interior (DOI) and the BLM
authority to regulate operations and air emissions, including equipment
and testing, on offshore and onshore operations on federal lands
subject to DOI authority.
• The Endangered Species Act (ESA) and Marine Mammal Protection Act
protect certain species’ habitats from adverse human impacts by
restricting operations or development at certain times and in certain
places. In 2020, the US Fish and Wildlife Service published two
proposed rules impacting designations under ESA, but on 20 January
2021 the Biden administration announced a review of these proposed
rules reducing the scope of habitat protections.
European Union
• The Industrial Emissions Directive (IED) 2010 provides the framework
for granting permits for major industrial sites. It lays down rules on
integrated prevention and control of air, water and soil pollution arising
from industrial activities. As part of the IED framework, additional
emission limit values are informed by sector specific and cross-sector
Best Available Technology (BAT) Conclusions. These include the BAT
Conclusions for the refining sector, for large combustion plants as well
as common wastewater and waste gas treatment and management
systems in the chemical sector. These may require bp to further reduce
its emissions, particularly its air and water emissions.
• The EU Regulation on substances that deplete the ozone layer 2009
(ODS Regulation) requires companies to reduce the use of ozone
depleting substances (ODSs) and phase out use of certain ODSs. bp
continues to replace ODSs in refrigerants and/or equipment in the EU
and elsewhere, in accordance with the Montreal Protocol and related
legislation.
• The Medium Combustion Plants Directive 2015 (MCPD) regulates
sulphur dioxide (SO2), nitrogen oxides (NOx) and particulates emissions
and monitoring of carbon monoxide (CO) emissions from certain mid-
size plants. It applies to new plants and by 2025 or 2030 to existing
plants, depending on their size.
• The National Emission Ceilings Directive 2016 (NECD) introduces
stricter emissions limits from 2020 and 2030, with new indicative
national targets applying from 2025. NECD has been implemented in
the UK by the National Emission Ceilings Regulations 2018. Each EU
Member State was also required to produce a National Air Pollution
Control Programme setting out the measures it will take to ensure
compliance with the 2020 and 2030 reduction commitments.
• The EU Registration, Evaluation Authorization and Restriction of
Chemicals (REACH) Regulation 2006 requires registration of chemical
substances manufactured in or imported into the EU, together with the
submission of relevant hazard and risk data. REACH affects our
manufacturing or trading/import operations in the EU. bp maintains
compliance by checking whether imports are covered by the
registrations of non-EU suppliers’ representatives, preparing and
submitting registration dossiers to cover new manufactured and
imported substances, and updating previously submitted registrations
as required. Some substances registered previously, including
substances supplied to us by third parties for our use, are now subject
to evaluation and review for potential authorization or restriction
procedures, and possible banning, by the European Chemicals Agency
and EU Member State authorities. In addition, bp’s facilities and
operations in several EU countries continue to undergo REACH
compliance inspections by the competent authority for the respective
EU Member State. An amendment to the Annex of the Regulation on
classification, labelling and packaging of substances and mixture (CLP
Regulation) requires harmonized notification of information on
hazardous materials (certain lubricant and fuel formations) to EU
Member State poison centres. The uniform notification rules apply as of
January 2020 for consumer products, from 2021 for professional and
2024 for industrial uses.
• The EU Offshore Safety Directive was adopted in 2013. Its purpose is
to introduce a harmonized regime aimed at reducing the potential
environmental, health and safety impacts of the offshore oil and gas
industry throughout EU waters. The Directive has been implemented in
the UK primarily through the Offshore Installations (Offshore Safety
Directive) (Safety Case etc.) Regulations 2015.
• The Water Framework Directive (WFD) published in 2000 aims to
protect the quantity and quality of ground and surface waters of the EU
Member States. The implementation in the EU Member States is still
ongoing, planned to be finalised by 2027. A Fitness Check
(comprehensive policy evaluation) of the EU Water Legislation launched
in 2019 concluded that the WFD is broadly fit for purpose. Future
proceedings on the determination of pollutants/priority substances as
well as environmental quality standards in line with the WFD may
require additional compliance efforts and increased costs for managing
freshwater withdrawals and discharges from bp’s EU operations.
United Kingdom
Following the UK’s exit from the European Union on 31 January
2020, the UK entered a transition period which ran until 31 December
2020. During the transition period, most EU law continued to apply to
the UK and therefore to bp’s UK business during that period. From 1
January 2021, operative EU laws were retained in UK law by the
European Union (Withdrawal) Act 2018. The vast majority of
environment related statutory instruments passed by the UK
Government in anticipation of Brexit have included no substantive
changes to the current EU underlying regime, but rather seek to
make the amendments required to allow their continued operation
after the transition period. The UK Government’s Environment Bill
and 25 Year Plan will be central to the UK’s environmental regime
going forward but further changes are as yet uncertain.
Other countries and regions
Regulations governing the discharge of treated water have also been
developed in countries outside of the US and EU. This includes
regulations in Trinidad and Angola which impacts bp’s production
operations in those countries. In Trinidad, bp commissioned a new
waste water treatment plant in 2020 to meet consent levels agreed
with the regulators to apply water discharge rules arising from the
Certificate of Environmental Clearance (CEC) Regulations 2001 and
associated Water Pollution Rules 2007. In Angola, bp has upgraded
produced water treatment systems to meet revised oil in water limits
for produced water discharge under Executive Decree ED 97-14.
The Abidjan Convention, along with the Additional Protocol published
in 2012, sets environmental quality standards for the discharge of
chemicals to the marine environment. The convention and associated
protocols has been ratified by 19 African nations including Senegal
and Mauritania. bp is currently constructing the offshore facilities to
include produced water management systems to meet the
environmental quality standards for our future gas operations in
Mauritania and Senegal.
324
bp Annual Report and Form 20-F 2020
« See Glossary
Environmental maritime regulations
bp’s shipping operations are subject to extensive national and
international regulations governing operations, training, pollution
prevention, liability, and insurance. These include:
• Liability and spill prevention and planning requirements governing,
among others, tankers, barges, and offshore facilities are imposed
by OPA in US waters. OPA also mandates a levy on imported and
domestically produced oil to fund oil spill responses. Some states,
including Alaska, Washington, Oregon and California, impose
additional liability for oil spills. Outside US territorial waters, bp
shipping tankers are subject to international pollution prevention,
liability, spill response and preparedness regulations developed
through the UN’s International Maritime Organization (IMO),
including the International Convention on Civil Liability for Oil
Pollution Damage, the International Convention for the Prevention of
Pollution from Ships (MARPOL), the International Convention on Oil
Pollution, Preparedness, Response and Co-operation, and the
International Convention on Civil Liability for Bunker Oil Pollution
Damage. In April 2010, the Hazardous and Noxious Substance
(HNS) Protocol 2010 was adopted to address issues that have
inhibited ratification of the International Convention on Liability and
Compensation for Damage in Connection with the Carriage of
Hazardous and Noxious Substances by Sea 1996. As at 31
December 2020, the HNS Convention had not entered into force.
• A global sulphur cap of 0.5% applies to marine fuel under MARPOL. In
order to comply, ships either need to consume low sulphur marine
fuels, operate on alternative low sulphur fuels such as LNG or
implement approved abatement technology to enable them to meet the
low sulphur emissions requirements while continuing to use higher
sulphur fuel. This global cap does not alter the lower limits that apply in
the sulphur oxides Emissions Control Areas established by the IMO.
• The Convention for the Protection of the Marine Environment of the
North-East Atlantic (OSPAR), aims to protect the marine
environment of the North-East Atlantic. The OSPAR 2012
Recommendation and Guideline for the implementation of a risk-
based approach to the management of produced water discharges
from offshore installations in the North Sea supports a key goal of
working towards eliminating harmful discharges. In 2020 the
International Association of Oil and Gas Producers issued a report
“Oil And Gas Risk Based Assessment of Offshore Produced Water
Discharges” which presents industry good practice and aims to
broaden the understanding and acceptance of Risk Based
Assessment (RBA) techniques internationally and improve
consistency in the application of assumptions, levels of
conservatism, and selection of risk endpoints.
To meet its financial responsibility requirements, bp Shipping maintains
marine oil pollution liability insurance in respect of its operated ships to a
maximum limit of $1 billion for each occurrence through mutual insurance
associations (P&I Clubs), although there can be no assurance that a spill
would necessarily be adequately covered by insurance or that liabilities
would not exceed insurance recoveries.
International trade sanctions
During the period covered by this report, non-US subsidiaries«, or other
non-US entities of BP, conducted limited activities in, or with persons
from, certain countries identified by the US Department of State as State
Sponsors of Terrorism or otherwise subject to US and EU sanctions
(Sanctioned Countries). Sanctions restrictions continue to be insignificant
to the group’s financial condition and results of operations. BP monitors
its activities with Sanctioned Countries, persons from Sanctioned
Countries and individuals and companies subject to US, EU and (following
the end of the Brexit transition period) UK sanctions and seeks to comply
with applicable sanctions laws and regulations.
BP has a 28.83% interest in and operates the Shah Deniz field in
Azerbaijan (Shah Deniz), has a 28.83% interest in and performs some
operations for a related gas pipeline entity, South Caucasus Pipeline
Company Limited (SCPC), and has a 23% non-operating interest in a
related gas marketing entity, Azerbaijan Gas Supply Company Limited
(AGSC). Naftiran Intertrade Co. Limited and NICO SPV Limited
(collectively, NICO) have a 10% non-operating interest in each of Shah
Additional disclosures
Deniz and SCPC and an 8% non-operating interest in AGSC. Shah Deniz,
SCPC and AGSC continue in operation as they were excluded from the
application of US sanctions and fall within the exception for certain natural
gas projects under Section 603 of the Iran Threat Reduction and Syria
Human Rights Act of 2012 (ITRA).
On 3 December 2018 BP entered into an agreement with, among others,
SOCAR and NICO pursuant to which SOCAR pays to BP Exploration
(Shah Deniz) Limited (BPXSD), as the Shah Deniz operator, compensation
for NICO’s waiver of its right to lift its share of Shah Deniz condensate.
Such amounts are used to cover cash calls to NICO in respect of
operating costs due from NICO to BPXSD. On 26 October 2020, OFAC
issued an amended licence in relation to these arrangements.
Following the imposition in 2011 of further US and EU sanctions against
Syria, BP terminated all sales of crude oil and petroleum products into
Syria, though BP continues to supply aviation fuel to non-governmental
Syrian resellers outside of Syria.
BP has a joint arrangement in Cuba which imports, manufactures,
markets and sells lubricants.
During 2014, the US and the EU imposed sanctions on certain sectors of
the Russian economy (energy, finance and defence/military) and on
certain individuals and entities, including Rosneft. These sectoral
sanctions include restrictions on the provision of financial assistance,
technical assistance, and services in relation to exploration and production
activity in deep water, shale, and offshore Arctic.
Additional US sanctions have been imposed since 2014, broadening the
scope of US sanctions on Russia-related activity to include certain
international deep water, shale, and offshore Arctic projects as well as the
provision of goods and services for Russian energy export pipelines. As of
1 January 2021, as a result of the UK’s exit from the EU, the UK has also
imposed Russian-related sanctions, which are broadly similar to existing
EU sanctions.
We are not aware of any material adverse effect on our current income
and investment in Russia or elsewhere as a consequence of these
sanctions.
BP maintains bank accounts and has registered and paid required fees to
maintain registrations of patents and trademarks in certain Sanctioned
Countries.
BP has equity interests in non-operated joint arrangements« with air fuel
sellers, resellers, and fuel delivery services around the world.
From time to time, the joint arrangement operator or other partners may
sell or deliver fuel to airlines from Sanctioned Countries or flights to
Sanctioned Countries, without BP's involvement.
BP has no control over the activities non-controlled associates« may
undertake in Sanctioned Countries or with persons from Sanctioned
Countries.
Disclosure pursuant to ITRA Section 219
To our knowledge, none of BP’s activities, transactions or dealings are
required to be disclosed pursuant to ITRA Section 219, with the following
possible exceptions.
On 17 July 2018, BP Iran Limited terminated its lease of an office in
Tehran. The office had been used for administrative activities. In 2020,
taxes with an aggregate US dollar equivalent value of approximately
$20,000 were paid from a BP trust account held with Tadvin Co. to Iranian
public entities. No gross revenues or net profits were attributable to these
activities.
BP has a 29.3% interest in Middle East Lubricants Company LLC
(Melubco), which is established and manufactures lubricants in the United
Arab Emirates. In May 2020, Melubco successfully appealed an Iranian
court judgment obtained against it in absentia for non-payment of
shipping fees. The applicant, an Iranian shipping company, had confused
Melubco with an unrelated, but similarly named, Iranian entity. In order to
do so, Melubco paid court filing fees equivalent to approximately $3,000
to the Tehran Judicial Services Office. Melubco does not, and has never,
done business in Iran.
« See Glossary
bp Annual Report and Form 20-F 2020
325
Material contracts
On 4 April 2016 the district court approved the Consent Decree among
BP Exploration & Production Inc., BP Corporation North America Inc., BP
p.l.c., the United States and the states of Alabama, Florida, Louisiana,
Mississippi and Texas (the Gulf states) which fully and finally resolved any
and all natural resource damages (NRD) claims of the United States, the
Gulf states, and their respective natural resource trustees and all Clean
Water Act (CWA) penalty claims, and certain other claims of the United
States and the Gulf states.
Concurrently, the definitive Settlement Agreement that bp entered into
with the Gulf states (Settlement Agreement) with respect to State claims
for economic, property and other losses became effective.
bp has filed the Consent Decree and the Settlement Agreement as
exhibits to its Annual Report on Form 20-F 2020 filed with the SEC. For
further details of the Consent Decree and the Settlement Agreement, see
Legal proceedings in bp Annual Report and Form 20-F 2015.
Property, plant and equipment
bp has freehold and leasehold interests in real estate and other tangible
assets in numerous countries, but no individual property is significant to
the group as a whole. For more on the significant subsidiaries« of the
group at 31 December 2020 and the group percentage of ordinary share
capital see Financial statements – Note 37. For information on significant
joint ventures« and associates« of the group see Financial statements –
Notes 16 and 17.
Related-party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 16 and Note
17. In the ordinary course of its business, the group enters into
transactions with various organizations with which some of its directors or
executive officers are associated. Except as described in this report, the
group did not have any material transactions or transactions of an unusual
nature with, and did not make loans to, related parties in the period
commencing 1 January 2020 to 2 March 2021.
Corporate governance practices
In the US, bp ADSs are listed on the New York Stock Exchange (NYSE).
The significant differences between bp’s corporate governance practices
as a UK company and those required by NYSE listing standards for US
companies are listed as follows:
Independence
In 2020 bp continued to apply its board governance principles. These
reflect the UK Corporate Governance Code approach to corporate
governance. As such, the way in which bp makes determinations of
directors’ independence differs from the NYSE rules. As set out on page
88, from 1 January 2021 bp has adopted terms of reference for the board
and each of its committees.
bp’s board governance principles require that all non-executive directors
be determined by the board to be ‘independent in character and
judgement and free from any business or other relationship which could
materially interfere with the exercise of their judgement’. The bp board
has determined that, in its judgement, all of the non-executive directors
are independent. In doing so, however, the board did not explicitly take
into consideration the independence requirements outlined in the NYSE’s
listing standards.
Committees
bp has a number of board committees that are broadly comparable in
purpose and composition to those required by NYSE rules for domestic
US companies. For instance, bp has a remuneration (rather than a
compensation) committee. bp also has an audit committee, which NYSE
rules require for both US companies and foreign private issuers. These
committees are composed solely of non-executive directors whom the
board has determined to be independent, in the manner described above.
The bp board governance principles prescribe the composition, main tasks
and requirements of each of the committees (see the board committee
reports on pages 92-102 and 105). Therefore, during 2020 bp did not have
separate charters for each committee. As from the start of 2021 each of
the board committees has adopted its own terms of reference which set
out their respective roles and responsibilities.
Under US securities law and the listing standards of the NYSE, bp is
required to have an audit committee that satisfies the requirements of
Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE
Listed Company Manual. bp’s audit committee complies with these
requirements. The bp audit committee does not have direct responsibility
for the appointment, reappointment or removal of the independent
auditors. Instead, it follows the UK Companies Act 2006 and the UK
Corporate Governance code 2018 by making recommendations to the
board on these matters for it to put forward for shareholder approval at
the AGM.
One of the NYSE’s additional requirements for the audit committee states
that at least one member of the audit committee is to have ‘accounting or
related financial management expertise’. The board determined that
Brendan Nelson possesses such expertise and also possesses the
financial and audit committee experiences set forth in both the UK
Corporate Governance Code and SEC rules (see Audit committee report
on page 94). Mr Nelson is the audit committee financial expert as defined
in Item 16A of Form 20-F.
Shareholder approval of equity compensation plans
The NYSE rules for US companies require that shareholders must be
given the opportunity to vote on all equity-compensation plans and
material revisions to those plans. bp complies with UK requirements that
are similar to the NYSE rules. The board, however, does not explicitly take
into consideration the NYSE’s detailed definition of what are considered
‘material revisions’.
Code of ethics
The NYSE rules require that US companies adopt and disclose a code of
business conduct and ethics for directors, officers and employees. bp has
adopted a code of conduct, which applies to all employees and members
of the board, and has board governance principles that address the
conduct of directors. In addition bp has adopted a code of ethics for
senior financial officers as required by the SEC. bp considers that these
codes and policies address the matters specified in the NYSE rules for US
companies.
Code of ethics
The company has adopted a code of ethics for its group chief executive,
chief financial officer, group controller, group head of audit and chief
accounting officer as required by the provisions of Section 406 of the
Sarbanes-Oxley Act of 2002 and the rules issued by the SEC. There have
been no waivers from the code of ethics relating to any officers.
bp also has a code of conduct, which is applicable to all employees,
officers and members of the board. This was updated (and published) in
July 2014.
Controls and procedures
Evaluation of disclosure controls and procedures
The company maintains ‘disclosure controls and procedures’, as such
term is defined in Exchange Act Rule 13a-15(e), that are designed to
ensure that information required to be disclosed in reports the company
files or submits under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the
Securities and Exchange Commission rules and forms, and that such
information is accumulated and communicated to management, including
the company’s group chief executive and chief financial officer, as
appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, our
management, including the group chief executive and chief financial
officer, recognize that any controls and procedures, no matter how well
designed and operated, can provide only reasonable, not absolute,
assurance that the objectives of the disclosure controls and procedures
are met. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control
issues and instances of fraud within the company, if any, have been
326
bp Annual Report and Form 20-F 2020
« See Glossary
detected. Further, in the design and evaluation of our disclosure controls
and procedures our management necessarily was required to apply its
judgement in evaluating the costs and benefits of possible control and
procedure design options. Also, we have investments in unconsolidated
entities. As we do not control these entities, our disclosure controls and
procedures with respect to such entities are necessarily substantially
more limited than those we maintain with respect to our consolidated
subsidiaries«. Because of the inherent limitations in a cost-effective
control system, misstatements due to error or fraud may occur and not be
detected. The company’s disclosure controls and procedures have been
designed to meet, and management believes that they meet, reasonable
assurance standards.
The company’s management, with the participation of the company’s
group chief executive and chief financial officer, has evaluated the
effectiveness of the company’s disclosure controls and procedures
pursuant to Exchange Act Rule 13a-15(b) as of the end of the period
covered by this annual report. Based on that evaluation, the group chief
executive and chief financial officer have concluded that the company’s
disclosure controls and procedures were effective at a reasonable
assurance level.
Management’s report on internal control over financial
reporting
Management of bp is responsible for establishing and maintaining
adequate internal control over financial reporting. bp’s internal control over
financial reporting is a process designed under the supervision of the
principal executive and financial officers to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of bp’s
financial statements for external reporting purposes in accordance with
IFRS.
As of the end of the 2020 fiscal year, management conducted an
assessment of the effectiveness of internal control over financial
reporting in accordance with the criteria in the UK Financial Reporting
Council’s Guidance on Risk Management, Internal Control and Related
Financial and Business Reporting relating to internal control over financial
reporting. Based on this assessment, management has determined that
bp’s internal control over financial reporting as of 31 December 2020 was
effective.
The company’s internal control over financial reporting includes policies
and procedures that pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect transactions and
dispositions of assets; provide reasonable assurances that transactions
are recorded as necessary to permit preparation of financial statements in
accordance with IFRS and that receipts and expenditures are being made
only in accordance with authorizations of management and the directors
of bp; and provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of bp’s assets
that could have a material effect on our financial statements. bp’s internal
control over financial reporting as of 31 December 2020 has been audited
by Deloitte LLP, an independent registered public accounting firm, as
stated in their report appearing on page 154 of bp Annual Report and
Form 20-F 2020.
Changes in internal control over financial reporting
There were no changes in the group’s internal control over financial
reporting that occurred during the period covered by the Form 20-F that
have materially affected or are reasonably likely to materially affect our
internal control over financial reporting.
Principal accountant's fees and
services
The audit committee has established policies and procedures for the
engagement of the independent registered public accounting firm,
Deloitte LLP, to render audit and certain assurance services. The policies
provide for pre-approval by the audit committee of specifically defined
audit, audit-related, non-audit and other services that are not prohibited by
regulatory or other professional requirements. Deloitte is engaged for
these services when its expertise and experience of bp are important.
Most of this work is of an audit nature. The committee regularly reviews
Additional disclosures
the policy, including in 2020, when it was updated to reflect changes
resulting from the FRC Ethical Standard (December 2019).
Under the policy, pre-approval is given for specific services within the
following categories: advice on accounting, auditing and financial reporting
matters; internal accounting and risk management control reviews
(excluding any services relating to information systems design and
implementation); non-statutory audit; project assurance and advice on
business and accounting process improvement (excluding any services
relating to information systems design and implementation relating to
bp’s financial statements or accounting records); provision of, or access
to, Deloitte publications, workshops, seminars and other training
materials; provision of reports from data gathered on non-financial policies
and information; provision of the independent third party audit in
accordance with US Generally Accepted Government Auditing Standards,
over the company’s Conflict Minerals Report – where such a report is
required under the SEC rule ‘Conflict Minerals’, issued in accordance with
Section 1502 of the Dodd Frank Act; and assistance with understanding
non-financial regulatory requirements. bp operates a two-tier system for
audit and non-audit services. For audit related services, the audit
committee has a pre-approved aggregate level, within which specific
work may be approved by management. Non-audit services are pre-
approved for management to authorize per individual engagement, but
above a defined level must be approved by the chairman of the audit
committee or the full committee. In response to the revised regulatory
guidelines of the UK Financial Reporting Council, the audit committee
reviewed and updated its policies with effect from 1 January 2017 and in
2018 further updated its policies to clarify the engagement of the
incoming auditor, Deloitte, and the outgoing auditor Ernst & Young to
ensure independence. The defined maximum level for pre-approval has
been reduced in line with FRC guidance on ‘non-trivial’ engagements. The
audit committee has delegated to the chairman of the audit committee
authority to approve permitted services provided that the chairman
reports any decisions to the committee at its next scheduled meeting.
Any proposed service not included in the approved service list must be
approved in advance by the audit committee chairman and reported to the
committee, or approved by the full audit committee in advance of
commencement of the engagement.
The audit committee evaluates the performance of the auditor each year.
The audit fees payable to Deloitte are reviewed by the committee in the
context of other global companies for cost effectiveness. The committee
keeps under review the scope and results of audit work and the
independence and objectivity of the auditor. External regulation and bp
policy requires the auditor to rotate its lead audit partner every five years.
See Financial statements – Note 36 and Audit committee report on page
94 for details of fees for services provided by the auditor.
Directors’ report information
This section of bp Annual Report and Form 20-F 2020 forms part of, and
includes certain disclosures which are required by law to be included in,
the Directors’ report.
Indemnity provisions
In accordance with BP’s Articles of Association, on appointment each
director is granted an indemnity from the company in respect of liabilities
incurred as a result of their office, to the extent permitted by law. These
indemnities were in force throughout the financial year and at the date of
this report. In respect of those liabilities for which directors may not be
indemnified, the company maintained a directors’ and officers’ liability
insurance policy throughout 2020. During the year, a review of the terms
and scope of the policy was undertaken as part of the annual renewal.
Although their defence costs may be met, neither the company’s
indemnity nor insurance provides cover in the event that the director is
proved to have acted fraudulently or dishonestly. Certain subsidiaries«
are trustees of the group’s pension schemes. Each director of these
subsidiaries is granted an indemnity from the company in respect of
liabilities incurred as a result of such a subsidiary’s activities as a trustee
of the pension scheme, to the extent permitted by law. These
indemnities were in force throughout the financial year and at the date of
this report.
« See Glossary
bp Annual Report and Form 20-F 2020
327
Financial risk management objectives and policies
The disclosures in relation to financial risk management objectives and
policies, including the policy for hedging, are included in How we manage
risk on page 64, Liquidity and capital resources on page 306 and Financial
statements – Notes 29 and 30.
Exposure to price risk, credit risk, liquidity risk and cash
flow risk
The disclosures in relation to exposure to price risk, credit risk, liquidity
risk and cash flow risk are included in Financial statements – Note 29.
Important events since the end of the financial year
Disclosures of the particulars of the important events affecting bp which
have occurred since the end of the financial year are included in the
Strategic report as well as in other places in the Directors’ report.
Likely future developments in the business
An indication of the likely future developments in the business of the
company is included in the Strategic report.
Research and development
Indications of our activities in the field of research and development are
provided throughout the Strategic report and the Directors’ report
including examples on pages 16 (developing next-gen mobility solutions),
17 (driving digital innovation including through bp ventures and
Launchpad), 19 (partnering to develop a project to produce hydrogen from
water), 36 (innovation and engineering) and 63 (collaborating with
universities and academic research). See also page 183 for our
expenditure on research and development.
Branches
As a global group our interests and activities are held or operated through
subsidiaries, branches, joint arrangements« or associates« established
in – and subject to the laws and regulations of – many different
jurisdictions.
Employees
Disclosures in respect of how the directors have engaged with
employees and had regard to their interests are included in How the
board has engaged with shareholders, the workforce and other
stakeholders on page 86 and section 172 statement on pages 63, 82 and
83.
The disclosures concerning policies in relation to the employment of
disabled persons and employee involvement are included in Sustainability
– People and society on page 57.
Employee share schemes
Certain shares held as a result of participation in some employee share
plans carry voting rights. Voting rights in respect of such shares are
exercisable via a nominee. Dividend waivers are in place in respect of
unallocated shares held in employee share plan trusts.
Suppliers, customers and others
Disclosures in respect of how the directors have engaged with suppliers,
customers and others in business relationships with the company are
included in How the board has engaged with shareholders, the workforce
and other stakeholders on page 86 and section 172 statement on pages
63, 82 and 83.
Change of control provisions
On 5 October 2015, the United States lodged with the district court in
MDL 2179 a proposed Consent Decree between the United States, the
Gulf states, BP Exploration & Production Inc., BP Corporation North
America Inc. and BP p.l.c., to fully and finally resolve any and all natural
resource damages claims of the United States, the Gulf states and their
respective natural resource trustees and all Clean Water Act penalty
claims, and certain other claims of the United States and the Gulf states.
Concurrently, bp entered into a definitive Settlement Agreement with the
five Gulf states (Settlement Agreement) with respect to state claims for
economic, property and other losses. On 4 April 2016, the district court
approved the Consent Decree, at which time the Consent Decree and
Settlement Agreement became effective. The federal government and
the Gulf states may jointly elect to accelerate the payments under the
Consent Decree in the event of a change of control or insolvency of BP
p.l.c., and the Gulf states individually have similar acceleration rights
under the Settlement Agreement. For further details of the Consent
Decree and the Settlement Agreement, see Legal proceedings in BP
Annual Report and Form 20-F 2015.
Greenhouse gas emissions, energy consumption and
energy efficiency
Disclosures in relation to greenhouse gas emissions, energy consumption
and energy efficiency are included in Sustainability – on page 50.
Disclosures required under Listing
Rule 9.8.4R
The information required to be disclosed by Listing Rule 9.8.4R can be
located as set out below:
Information required
(1) Amount of interest capitalized
(2) – (4)
(5), (6) Waiver of director emoluments
(7) – (11)
(12), (13) Dividend waivers
(14)
Page
183
Not applicable
121
Not applicable
328
Not applicable
328
bp Annual Report and Form 20-F 2020
« See Glossary
Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private
Securities Litigation Reform Act of 1995 (the ‘PSLRA’) and the general
doctrine of cautionary statements, bp is providing the following cautionary
statement.
This document contains certain forecasts, projections and forward-looking
statements - that is, statements related to future, not past, events and
ircumstances - with respect to the financial condition, results of
operations and businesses of bp and certain of the plans and objectives of
bp with respect to these items. These statements may generally, but not
always, be identified by the use of words such as ‘will’, ‘expects’, ‘is
expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’,
‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In
particular, among other statements, (i) certain statements in the
Chairman’s letter (pages 4-5), the Group chief executive’s letter (pages
6-7), the Strategic report (inside cover and pages 1-70), Additional
disclosures (pages 301-330) and Shareholder information (pages 331-340),
including but not limited to statements under the headings ‘Our Energy
Outlook’, ‘Reinventing bp – our business model’, ‘Reinventing bp – our
strategic focus areas’, ‘Reinventing bp – our financial frame’, ‘2021
guidance’ and ‘Reinventing bp – in line with the Paris goals’ and including
but not limited to statements regarding: plans and expectations relating to
operating cash flow, capital expenditure (including total capital
expenditure, organic capital expenditure and inorganic capital
expenditure), maintaining a strong financial frame, deleveraging bp’s
balance sheet, working capital and operating cash flows, liquidity, capital
discipline, future sustainable free cash flow and shareholder distributions,
allocation of capital to bp’s energy transition strategy, amount or timing of
payments related to divestment proceeds, net debt, gearing and future
dividend payments and share buybacks; bp’s ambition to be a net zero
company by 2050 or sooner, including its aims regarding Scope 1, Scope
2 and Scope 3 emissions, its expectations for the energy transition and
the carbon content of its oil and gas production, while operating a high-
quality base business; bp’s plan to amplify value by focusing on
integrating energy systems, partnering with countries, cities and
industries, and driving digital innovation; expectations regarding medium
and long-term oil prices, the consistency of pricing assumptions with
scenarios that are consistent with the Paris goals and bp’s resilience to
Paris-consistent pathways; expectations regarding world energy demand,
including the growth in relative demand for renewables, oil and gas, and
the proportional growth of renewables; expectations regarding bp’s short,
medium- and long-term targets and aims for emissions and carbon
intensity of bp’s production and marketed products, and statements
regarding the resilience of bp’s strategy and portfolio across multiple
climate scenarios and the uncertainties in the energy transition; plans and
expectations regarding bp’s level of investment in energy sources and
technologies other than oil and gas resources and reserves, including
plans to increase investment in low carbon from around $750 million in
2020 to $3-4 billion by 2025 and to around $5 billion a year in 2030, with
transition capital spend to be as much as 50% of capex in 2030; plans and
expectations to significantly increase bp’s investment in low carbon
activities in this decade, while also operating a high-quality base business;
plans and expectations regarding bp’s five aims to get bp to net zero,
including the aim to be net zero across its entire operations on an
absolute basis by 2050 or sooner, the aim to be net zero on an absolute
basis across the carbon in its upstream oil and gas production by 2050 or
sooner, the aim to cut the carbon intensity of products sold by 50% by
2050 or sooner, the aim to install methane measurement at all existing
major oil and gas processing sites by 2023, publish the data, and then
drive a 50% reduction in methane intensity of operations, and the aim to
increase the proportion of investment bp makes into its non-oil and gas
businesses; plans and expectations regarding bp’s five aims to get the
world to net zero carbon emissions, including the aim to more actively
advocate for policies that support net zero, including carbon pricing, the
aim to incentivize bp’s global workforce to deliver on these aims and
mobilize them to become advocates for net zero, the aim to set new
expectations for relationships with trade associations around the globe,
the aim to be recognized as an industry leader for the transparency of its
reporting and the aim to launch a new team to create integrated clean
energy and mobility solutions; expectations with respect to oil and gas
supply and demand and prices; expectations with respect to the world
energy mix, production, consumption and emissions; plans and
Additional disclosures
expectations with respect to low carbon spend in 2021; expectations with
respect to transition capital, and the percentage of capital expenditure
that will be low-carbon; expectations that the aftermath of the pandemic
will accelerate the pace of transition to a lower carbon economy and
energy system; expectations that the Empire Wind project in New York
state will have 2GW generating capacity once operational and Beacon
Wind will have 2.4GW generating capacity once operational; expectations
regarding future legislative or regulatory action related to greenhouse
gases, including emissions disclosure, emissions trading, and fuel-specific
regulations, and their impact on bp; expectations regarding pensions and
other post-retirement benefits, including contributions; expectations
regarding payments under contractual obligations and sales
commitments; expectations that around 10,000 employees will leave bp
by early 2022; plans and expectations regarding bp’s workforce, including
bp’s targets regarding diversity, inclusion and equality; expectations
regarding bp’s ability to prevent violations of its code of conduct, including
its anti-bribery and corruption policies and procedures; plans and
expectations regarding the new leadership structure and governance
framework, including areas of focus and effectiveness; plans for
incentivising bp’s global workforce; policies and goals related to risk
management plans; plans and expectations regarding control deficiencies;
expectations regarding bp’s ability to prevent, respond to and recover
from cyberattacks or hostile actions; plans and projections regarding oil
and gas reserves, including the turnover time of proved undeveloped
reserves to proved developed reserves and volume of turnover;
expectations regarding the costs of environmental restoration,
remediation and abatement programmes; plans and expectations
regarding bp’s portfolio, including to maintain a focused portfolio, to
manage the portfolio through disciplined investment to support growing
returns and to focus on highest-quality barrels; expectations that by 2030
bp’s hydrocarbon production will be around 40% lower relative to 2019
due to active management and high-grading of the portfolio, including
divestment of non-core assets; plans and expectations that bp will not
undertake exploration activity in new countries; expectations regarding
contingent liabilities and their impact on bp; expectations regarding the
future value of assets; expectations with respect to reserves bookings
from new discoveries; plans and expectations with regard to the supply
and trading function, the fuels and the lubricants businesses; plans and
expectations with regard to new technologies, including their efficiency
and impact on production; plans and expectations regarding sales
commitments of bp and its equity-accounted entities; expectations
regarding underlying production and capital investment; expectations with
respect to ROACE and earnings before interest, tax, depreciation and
amortisation; plans and expectations regarding investment, development,
and production levels and the timing thereof with respect to projects and
partnerships in Angola, Australia, Azerbaijan, Brazil, Egypt, the Gambia,
India, Indonesia, Mexico, Russia, São Tomé and Príncipe, Turkey, Oman,
the UK North Sea, the Gulf of Mexico, and the continental United States;
expectations regarding refining margins; plans to undertake joint
exploration and development with Rosneft and plans and expectations for
the Strategic Collaboration Agreement signed between Rosneft and bp;
expectations regarding future government action, regulations and policy,
their impact on bp’s business and plans regarding compliance with such
regulations; expectations regarding legal and trial proceedings, court
decisions, potential investigations and civil actions by regulators,
government entities and/ or other entities or parties, and the timing and
potential impact of such proceedings and bp’s intentions in respect
thereof; plans and expectations regarding relationships with governments,
customers, partners, suppliers, communities and key stakeholders; plans
to produce 900,000boe/d from new projects by 2021 and expectations
regarding operating cash margins of this production; plans and
expectations for bp’s Jio-bp joint venture with Reliance, including the
expectation for 5,500 Jio-bp retail sites by 2025; plans and expectations to
deliver 2021 financial targets; plans to increase investment in low carbon
to $3-4 billion by 2025 and to around $5 billion a year in 2030;
expectations related to delivery and execution of Atlantis Phase 3 in the
US Gulf of Mexico; expectations regarding customer touchpoints, number
of strategic convenience sites, number of retail sites in growth markets,
Castrol sales and other operating revenues, number of electric vehicle
charge points, margin share from convenience and electrification, unit
production costs, Upstream production, Upstream plant reliability, refining
throughout, refining availability, developed renewables to final investment
decision, bioenergy production, LNG portfolio, and traded electricity;
« See Glossary
bp Annual Report and Form 20-F 2020
329
preferences; regulatory or legal actions including the types of
enforcement action pursued and the nature of remedies sought or
imposed; the actions of prosecutors, regulatory authorities and courts;
delays in the processes for resolving claims; amounts ultimately
determined to be payable and the timing of payments relating to the Gulf
of Mexico oil spill; exchange rate fluctuations; development and use of
new technology; recruitment and retention of a skilled workforce; the
success or otherwise of partnering; the actions of competitors, trading
partners, contractors, subcontractors, creditors, rating agencies and
others; bp’s access to future credit resources; business disruption and
crisis management; the impact on bp’s reputation of ethical misconduct
and noncompliance with regulatory obligations; trading losses; major
uninsured losses; decisions by Rosneft’s management and board of
directors; the actions of contractors; natural disasters and adverse
weather conditions; changes in public expectations and other changes to
business conditions; public health situations (including an outbreak of an
epidemic or pandemic); wars and acts of terrorism; cyberattacks or
sabotage; and other factors discussed elsewhere in this report including
under Risk factors (pages 67-70). In addition to factors set forth
elsewhere in this report, those set out above are important factors,
although not exhaustive, that may cause actual results and developments
to differ materially from those expressed or implied by these forward-
looking statements.
Statements regarding competitive position
Statements referring to bp’s competitive position are based on the
company’s belief and, in some cases, rely on a range of sources, including
investment analysts’ reports, independent market studies and bp’s
internal assessments of market share based on publicly available
information about the financial results and performance of market
participants.
expectations regarding oil prices, including for long-term prices to be
affected by the enduring impact of the COVID-19 pandemic, the decisions
of OPEC+, confidence in efforts to manage the rollout of vaccination and
further virus control measures; expectations regarding Upstream reported
production excluding Rosneft , total capital expenditure, depreciation,
depletion and amortisation charges, Gulf of Mexico oil spill payments
(post-tax), the Other business and corporate annual charge and underlying
quarterly charge, and the effective tax rate and the underlying effective
tax rate; plans and expectations regarding the effectiveness of the
group’s foreign currency exchange risk management; expectations
regarding bp’s partnership with Equinor for offshore wind in the US,
including bp’s expectation of pursuing further opportunities for offshore
wind in the US, and regarding bp’s partnership with Ørsted on an
industrial-scale project to produce hydrogen from water, powered by
wind; expectations regarding the US gas market in 2021 as supply
declines and demand for LNG exports recovers and that the current
tightness on global LNG markets and higher US gas prices will lift other
regional gas prices; expectations for limited growth in oil supply from non-
OPEC+ countries coupled with active market management from OPEC+
leading to normalization of the currently high inventory levels, with prices
subject to the decisions of OPEC+; expectations that US gas markets are
likely to benefit from lower production and a recovery in international LNG
demand driven by demand in Asia; expectations that demand for refined
products will remain strong over the remaining useful life of existing
assets; expectations that the majority of bp’s Upstream oil and gas
properties will start decommissioning within the next two decades;
expectations that the majority of bp’s reserves and resources that support
the carrying value of the group’s existing oil and gas properties are
expected to be produced over the next 10 years; expectations that
reported production will be lower due to the impact of the ongoing
divestment programme; expectations regarding level and volatility of
other businesses and corporate charges for 2021; plans and expectations
regarding bp’s in-scope projects’ impact on biodiversity; expectation’s
regarding bp’s impact on air emissions and water use and management;
expectations regarding fulfillment of existing delivery commitments for oil
and gas; expectations regarding Gulf of Mexico oil spill payments;
expectations that first oil from the Thunder Horse South Expansion will be
reached in the third quarter of 2021 and that first oil for the Mad Dog 2
project will be reached in the second quarter of 2022; expectations that
the Cassia Compression project will start up in 2022; expectations that
first production from the Total-operated Zinia 2 deep offshore
development project will occur in 2021; expectation that first production
from the Platina project will occur in 2021; expectation for start-up of the
West Nile Delta Raven project in the first quarter of 2021; expectations
that the Tangguh expansion project will start-up in 2022; and plans and
expectations regarding bp Ventures and Launchpad; and (ii) certain
statements in Corporate governance (pages 71-102) and the Directors’
remuneration report (pages 103-126) with regard to: the anticipated future
composition of the board of directors and the effects thereof; the board’s
goals and areas of focus, including changes to KPIs and those goals
stemming from the board’s annual evaluation; plans and expectations
regarding directors’ share ownership and remuneration; plans regarding
the governance and remuneration processes; and goals, activities and
areas of focus of board committees, are all forward looking in nature. By
their nature, forward-looking statements involve risk and uncertainty
because they relate to events and depend on circumstances that will or
may occur in the future and are outside the control of bp. Actual results
may differ materially from those expressed in such statements,
depending on a variety of factors, including: the specific factors identified
in the discussions accompanying such forward looking statements; the
effects of the COVID-19 pandemic and uncertainties about its impact and
duration; the receipt of relevant third party and/or regulatory approvals;
the timing and level of maintenance and/or turnaround activity; the timing
and volume of refinery additions and outages; the timing of bringing new
projects onstream; the timing, quantum and nature of certain acquisitions
and divestments; future levels of industry product supply, demand and
pricing, including supply growth in North America; OPEC+ quota
restrictions; production-sharing agreements effects; operational and
safety problems; potential lapses in product quality; economic and
financial market conditions generally or in various countries and regions;
political stability and economic growth in relevant areas of the world;
changes in laws and governmental regulations and policies, including
related to climate change; changes in social attitudes and customer
330
bp Annual Report and Form 20-F 2020
« See Glossary
Shareholder information
Shareholder information
Share prices and listings
Dividends
Shareholder taxation information
Major shareholders
Annual general meeting
Memorandum and Articles of Association
Purchases of equity securities by the issuer and
affiliated purchasers
Fees and charges payable by ADS holders
Fees and payments made by the Depositary to
the issuer
Documents on display
Shareholding administration
2021 Shareholder calendar
332
332
332
334
335
335
338
339
339
339
340
340
bp Annual Report and Form 20-F 2020
331
Share prices and listings
The following table shows dividends announced and paid by the company
per ADS for the past five years.
Markets and market prices
The primary market for the company’s ordinary shares (trading symbol
'BP.'), 8% cumulative first preference shares (trading symbol 'BP.A') and
9% cumulative second preference shares (trading symbol 'BP.B') is the
London Stock Exchange (LSE). The company’s ordinary shares are a
constituent element of the Financial Times Stock Exchange 100 Index.
In the US, the company’s securities are listed and traded on the New York
Stock Exchange (NYSE) in the form of ADSs (trading symbol 'BP'), for
which JPMorgan Chase Bank, N.A. is the depositary (the Depositary) and
transfer agent. The Depositary’s principal office is 383 Madison Avenue,
Floor 11, New York, NY, 10179, US. Each ADS represents six ordinary
shares. ADSs are evidenced by American depositary receipts (ADRs),
which may be issued in either certificated or book entry form.
The company's ordinary shares are also traded in the form of a global
depositary certificate representing the company's ordinary shares on the
Frankfurt, Hamburg and Dusseldorf Stock Exchanges.
On 25 February 2021, 849,802,947 ADSs (equivalent to approximately
5,098,817,682 ordinary shares or some 25.06% of the total issued share
capital, excluding shares held in treasury) were outstanding and were held
by approximately 72,535 ADS holders. Of these, about 71,703 had
registered addresses in the US at that date. One of the registered holders
of ADSs represents approximately 1,087,342 underlying holders.
On 25 February 2021, there were approximately 225,319 ordinary
shareholders. Of these shareholders, around 1,539 had registered
addresses in the US and held a total of some 4,381,925 ordinary shares.
Since a number of the ordinary shares and ADSs were held by brokers
and other nominees, the number of holders in the US may not be
representative of the number of beneficial holders or their respective
country of residence.
Dividends
The company’s current policy is to pay interim dividends on a quarterly
basis on its ordinary shares.
Its policy is also to announce dividends for ordinary shares in US dollars
and state an equivalent sterling dividend. Dividends on the company's
ordinary shares will be paid in sterling and on the company's ADSs in US
dollars. The rate of exchange used to determine the sterling amount
equivalent is the average of the market exchange rates in London over
the four business days prior to the sterling equivalent announcement
date. The directors may choose to declare dividends in any currency
provided that a sterling equivalent is announced. It is not the company’s
intention to change its current policy of announcing dividends on ordinary
shares in US dollars.
Information regarding dividends announced and paid by the company on
ordinary shares and preference shares is provided in Financial statements
– Note 10.
A Scrip Dividend Programme (Scrip Programme) was approved by
shareholders in 2010 and was renewed for a further three years at the
2018 AGM. It is proposed that the Scrip Programme be renewed for a
further three years at the 2021 AGM. It enabled the company's ordinary
shareholders and ADS holders to elect to receive dividends by way of
new fully paid ordinary shares (or ADSs in the case of ADS holders)
instead of cash. The operation of the Scrip Programme is always subject
to the directors’ decision to make the Scrip Programme offer available in
respect of any particular dividend.
The company announced on 29 October 2019 and as part of all
subsequent quarterly results announcements made since that the board
had suspended the Scrip Programme in respect of those quarterly
dividends. Ordinary shareholders and ADS holders (subject to certain
exceptions) may be able to participate in dividend reinvestment plans. Any
decisions with respect to future dividends will be made by the board of
BP p.l.c. following the end of each quarter.
Future dividends will be dependent on future earnings, the financial
condition of the group, the Risk factors set out on page 67 and other
matters that may affect the business of the group set out in Our strategy
on page 15 and in Liquidity and capital resources on page 306.
Dividends per ADSa
March
June September December
Total
60
60
60
60
2018
2017
2016
UK pence 42.08 41.50 45.35 47.59 176.52
US cents
240
60
UK pence 48.95 46.54 45.73 44.66 185.88
US cents
240
60
UK pence 43.01 44.66 47.58 48.15 183.40
US cents
243
UK pence 46.43 48.39 50.09 46.95 191.86
246
US cents 61.50 61.50 61.50 61.50
UK pence 48.94 50.05 24.26 23.50 146.75
189
US cents
a Dividends announced and paid by the company on ordinary and preference shares are provided in
63.00 63.00 31.50 31.50
60 61.50 61.50
2020
2019
60
60
60
Financial statements – Note 10.
There are currently no UK foreign exchange controls or restrictions on
remittances of dividends on the ordinary shares or on the conduct of the
company’s operations, other than restrictions applicable to certain
countries and persons subject to EU economic sanctions or those
sanctions adopted by the UK government which implement resolutions of
the Security Council of the United Nations.
Shareholder taxation information
This section describes the material US federal income tax and UK taxation
consequences of owning ordinary shares or ADSs to a US holder who
holds the ordinary shares or ADSs as capital assets for tax purposes. It
does not apply, however, inter alia to members of special classes of
holders some of which may be subject to other rules, including: tax-
exempt entities, life insurance companies, dealers in securities, traders in
securities that elect a mark-to-market method of accounting for securities
holdings, investors liable for alternative minimum tax, holders that,
directly or indirectly, hold 10% or more of the company’s shares (as
measured by voting power or value), holders that hold the shares or ADSs
as part of a straddle or a hedging or conversion transaction, holders that
purchase or sell the shares or ADSs as part of a wash sale for US federal
income tax purposes, or holders whose functional currency is not the US
dollar. In addition, if a partnership holds the shares or ADSs, the US
federal income tax treatment of a partner will generally depend on the
status of the partner and the tax treatment of the partnership and may not
be described fully below.
A US holder is any beneficial owner of ordinary shares or ADSs that is for
US federal income tax purposes (1) a citizen or resident of the US, (2) a
US domestic corporation, (3) an estate whose income is subject to US
federal income taxation regardless of its source, or (4) a trust if a US court
can exercise primary supervision over the trust’s administration and one
or more US persons are authorized to control all substantial decisions of
the trust.
This section is based on the tax laws of the United States, including the
Internal Revenue Code of 1986, as amended, its legislative history,
existing and proposed US Treasury regulations thereunder, published
rulings and court decisions, and the taxation laws of the UK, all as
currently in effect, as well as the income tax convention between the US
and the UK that entered into force on 31 March 2003 (the ‘Treaty’). These
laws are subject to change, possibly on a retroactive basis. This section
further assumes that each obligation under the terms of the deposit
agreement relating to bp ADSs and any related agreement will be
performed in accordance with its terms.
For purposes of the Treaty and the estate and gift tax Convention (the
‘Estate Tax Convention’) and for US federal income tax and UK taxation
purposes, a holder of ADRs evidencing ADSs will be treated as the owner
of the company’s ordinary shares represented by those ADRs. Exchanges
of ordinary shares for ADRs and ADRs for ordinary shares generally will
not be subject to US federal income tax or to UK taxation other than
stamp duty or stamp duty reserve tax, as described below.
332
bp Annual Report and Form 20-F 2020
« See Glossary
Shareholder information
Investors should consult their own tax adviser regarding the US federal,
state and local, UK and other tax consequences of owning and disposing
of ordinary shares and ADSs in their particular circumstances, and in
particular whether they are eligible for the benefits of the Treaty in
respect of their investment in the shares or ADSs.
adviser regarding the US tax treatment of the dividend fee in respect of
dividends. Dividends will be income from sources outside the US and
generally will be ‘passive category income’ or, in the case of certain US
holders, ‘general category income’, each of which is treated separately for
purposes of computing a US holder’s foreign tax credit limitation.
Taxation of dividends
UK taxation
Under current UK taxation law, no withholding tax will be deducted from
dividends paid by the company, including dividends paid to US holders.
A shareholder that is a company resident for tax purposes in the UK or
trading in the UK through a permanent establishment generally will not be
taxable in the UK on a dividend it receives from the company. A
shareholder who is an individual resident for tax purposes in the UK is
subject to UK tax on dividends received from the company, including
dividends received under the dividend reinvestment plan (DRIP) for
ordinary shareholders, but until 5 April 2016, was entitled to a tax credit
on cash dividends paid on ordinary shares or ADSs of the company equal
to one-ninth of the cash dividend.
From 6 April 2016 the dividend tax credit was replaced by a new tax-free
dividend allowance and dividends paid by the company on or after 6 April
2016 do not carry a UK tax credit. The dividend allowance was £5,000 but
this has been reduced to £2,000 as of 6 April 2018.
The dividend allowance of £2,000 means there is no UK tax due on the
first £2,000 of dividends received. Dividends above this level are subject
to tax at 7.5% for basic tax payers, 32.5% for higher rate tax payers and
38.1% for additional rate tax payers.
Although the first £2,000 of dividend income is not subject to UK income
tax, it does not reduce the total income for tax purposes. Dividends within
the dividend allowance still count towards basic or higher rate bands, and
may therefore affect the rate of tax paid on dividends received in excess
of the £2,000 allowance. For instance, if an individual has an annual gross
salary of £50,000 and also receives a dividend of £12,000 they will be
subject to the following scenario. The individual's personal allowance and
the basic rate tax band will be used up by the gross salary. The remaining
part of the salary and the whole of the dividend will be subject to tax at
the higher rate, although the dividend allowance will reduce the amount
of dividend subject to tax. The dividend of £12,000 will be reduced by the
dividend allowance of £2,000 leaving taxable dividend income of £10,000.
The dividend will be taxed at 32.5% so that the total tax payable on the
dividends is £3,250.
How the shareholder pays the tax arising on the dividend income depends
on the amount of dividend income and salary they receive in the tax year.
If less than £2,000 they will not need to report anything or pay any tax. If
between £2,000 and £10,000, the shareholder can pay what they owe by:
contacting the helpline; asking HMRC to change their tax code – the tax
will be taken from their wages or pension or through completion of the
‘Dividends’ section of their tax return, where one is being filed. If over
£10,000 they will be required to file a self-assessment tax return and
should complete the ‘Dividends’ section with details of the amounts
received.
US federal income taxation
A US holder is subject to US federal income taxation on the gross amount
of any dividend paid by the company (including dividends paid but
reinvested received under the Global Invest Direct (GID) Dividend
Reinvestment Plan for ADS holders) out of its current or accumulated
earnings and profits (as determined for US federal income tax purposes).
Dividends paid to a non-corporate US holder that constitute qualified
dividend income will be taxable to the holder at a preferential rate,
provided that the holder has a holding period in the ordinary shares or
ADSs of more than 60 days during the 121-day period beginning 60 days
before the ex-dividend date and meets other holding period requirements.
Dividends paid by the company with respect to the ordinary shares or
ADSs will generally be qualified dividend income.
For US federal income tax purposes, a dividend must be included in
income when the US holder, in the case of ordinary shares, or the
Depositary, in the case of ADSs, actually or constructively receives the
dividend and will not be eligible for the dividends-received deduction
generally allowed to US corporations in respect of dividends received
from other US corporations. US ADS holders should consult their own tax
As noted above in UK taxation, a US holder will not be subject to UK
withholding tax. Accordingly, the receipt of a dividend will not entitle the
US holder to a foreign tax credit.
The amount of the dividend distribution on the ordinary shares that is paid
in pounds sterling will be the US dollar value of the pounds sterling
payments made, determined at the spot pounds sterling/US dollar rate on
the date the dividend distribution is includible in income, regardless of
whether the payment is, in fact, converted into US dollars. Generally, any
gain or loss resulting from currency exchange fluctuations during the
period from the date the pounds sterling dividend payment is includible in
income to the date the payment is converted into US dollars will be
treated as ordinary income or loss and will not be eligible for the
preferential tax rate on qualified dividend income. The gain or loss
generally will be income or loss from sources within the US for foreign tax
credit limitation purposes.
Distributions in excess of the company’s earnings and profits, as
determined for US federal income tax purposes, will be treated as a
return of capital to the extent of the US holder’s basis in the ordinary
shares or ADSs and thereafter as capital gain, subject to taxation as
described in Taxation of capital gains – US federal income taxation section
below.
In addition, the taxation of dividends may be subject to the rules for
passive foreign investment companies (PFIC), described below under
‘Taxation of capital gains – US federal income taxation’. Distributions
made by a PFIC do not constitute qualified dividend income and are not
eligible for the preferential tax rate applicable to such income.
Taxation of capital gains
UK taxation
A US holder may be liable for both UK and US tax in respect of a gain on
the disposal of ordinary shares or ADSs if the US holder is (1) resident for
tax purposes in the United Kingdom at the date of disposal, (2) if he or
she has left the UK for a period not exceeding five complete tax years
between the year of departure from and the year of return to the UK and
acquired the shares before leaving the UK and was resident in the UK in
the previous four out of seven tax years before the year of departure, (3) a
US domestic corporation resident in the UK by reason of its business
being managed or controlled in the UK or (4) a citizen of the US that
carries on a trade or profession or vocation in the UK through a branch or
agency or a corporation that carries on a trade, profession or vocation in
the UK, through a permanent establishment, and that has used, held, or
acquired the ordinary shares or ADSs for the purposes of such trade,
profession or vocation of such branch, agency or permanent
establishment. However, such persons may be entitled to a tax credit
against their US federal income tax liability for the amount of UK capital
gains tax or UK corporation tax on chargeable gains (as the case may be)
that is paid in respect of such gain.
Under the Treaty, capital gains on dispositions of ordinary shares or ADSs
generally will be subject to tax only in the jurisdiction of residence of the
relevant holder as determined under both the laws of the UK and the US
and as required by the terms of the Treaty.
Under the Treaty, individuals who are residents of either the UK or the US
and who have been residents of the other jurisdiction (the US or the UK,
as the case may be) at any time during the six years immediately
preceding the relevant disposal of ordinary shares or ADSs may be
subject to tax with respect to capital gains arising from a disposition of
ordinary shares or ADSs of the company not only in the jurisdiction of
which the holder is resident at the time of the disposition but also in the
other jurisdiction.
For gains on or after 23 June 2010, the UK Capital Gains Tax rate will be
dependent on the level of an individual’s taxable income. Where total
taxable income and gains after all allowable deductions are less than the
upper limit of the basic rate income tax band of £37,500 (for 2020/21), the
rate of Capital Gains Tax will be 10%. For gains (and any parts of gains)
above that limit the rate will be 20%.
« See Glossary
bp Annual Report and Form 20-F 2020
333
From 6 April 2008, entitlement to the annual exemption is based on an
individual’s circumstances (taking into account Domicile status,
remittance basis of taxation and number of years in the UK). For
individuals who are entitled to the exemption for 2020/21, this has been
set at £12,300. Corporation tax on chargeable gains is levied at 19 per
cent for companies from 1 April 2017.
US federal income taxation
A US holder who sells or otherwise disposes of ordinary shares or ADSs
will recognize a capital gain or loss for US federal income tax purposes
equal to the difference between the US dollar value of the amount
realized on the disposition and the US holder’s tax basis, determined in
US dollars, in the ordinary shares or ADSs. Any such capital gain or loss
generally will be long-term gain or loss, subject to tax at a preferential rate
for a non-corporate US holder, if the US holder’s holding period for such
ordinary shares or ADSs exceeds one year. The tax basis of shares
acquired through reinvested dividends under the GID Dividend
Reinvestment Plan for ADS holders) is equal to the fair market value of
the stock on the investment date. The holding period for shares acquired
under the plan begins the day after the applicable investment date.
Gain or loss from the sale or other disposition of ordinary shares or ADSs
will generally be income or loss from sources within the US for foreign tax
credit limitation purposes. The deductibility of capital losses is subject to
limitations.
We do not believe that ordinary shares or ADSs will be treated as stock of
a passive foreign investment company (PFIC) for US federal income tax
purposes, but this conclusion is a factual determination that is made
annually and thus is subject to change. If we are treated as a PFIC, unless
a US holder elects to be taxed annually on a mark-to-market basis with
respect to ordinary shares or ADSs, any gain realized on the sale or other
disposition of ordinary shares or ADSs would in general not be treated as
capital gain. Instead, a US holder would be treated as if he or she had
realized such gain rateably over the holding period for ordinary shares or
ADSs and would be taxed at the highest tax rate in effect for each such
year to which the gain was allocated, in addition to which an interest
charge in respect of the tax attributable to each such year would apply.
Certain ‘excess distributions’ would be similarly treated if we were
treated as a PFIC.
Additional tax considerations
Scrip Programme
Until the publication of the 2019 third quarter results, the company had an
optional Scrip Programme, wherein holders of bp ordinary shares or ADSs
could elect to receive any dividends in the form of new fully paid ordinary
shares or ADSs of the company instead of cash. Please consult your tax
adviser for the consequences to you.
UK inheritance tax
The Estate Tax Convention applies to inheritance tax. ADSs held by an
individual who is domiciled for the purposes of the Estate Tax Convention
in the US and is not for the purposes of the Estate Tax Convention a
national of the UK will not be subject to UK inheritance tax on the
individual’s death or on transfer during the individual’s lifetime unless,
among other things, the ADSs are part of the business property of a
permanent establishment situated in the UK used for the performance of
independent personal services. In the exceptional case where ADSs are
subject to both inheritance tax and US federal gift or estate tax, the Estate
Tax Convention generally provides for tax payable in the US to be credited
against tax payable in the UK or for tax paid in the UK to be credited
against tax payable in the US, based on priority rules set forth in the
Estate Tax Convention.
UK stamp duty and stamp duty reserve tax
The statements below relate to what is understood to be the current
practice of HM Revenue & Customs in the UK under existing law.
Provided that any instrument of transfer is not executed in the UK and
remains at all times outside the UK and the transfer does not relate to any
matter or thing done or to be done in the UK, no UK stamp duty is payable
on the acquisition or transfer of ADSs. Neither will an agreement to
transfer ADSs in the form of ADRs give rise to a liability to stamp duty
reserve tax.
Purchases of ordinary shares, as opposed to ADSs, through the CREST
system of paperless share transfers will be subject to stamp duty reserve
tax at 0.5%. The charge will arise as soon as there is an agreement for
the transfer of the shares (or, in the case of a conditional agreement,
when the condition is fulfilled). The stamp duty reserve tax will apply to
agreements to transfer ordinary shares even if the agreement is made
outside the UK between two non-residents. Purchases of ordinary shares
outside the CREST system are subject either to stamp duty at a rate of
£5 per £1,000 (or part, unless the stamp duty is less than £5, when no
stamp duty is charged), or stamp duty reserve tax at 0.5%. Stamp duty
and stamp duty reserve tax are generally the liability of the purchaser.
A subsequent transfer of ordinary shares to the Depositary’s nominee will
give rise to further stamp duty at the rate of £1.50 per £100 (or part) or
stamp duty reserve tax at the rate of 1.5% of the value of the ordinary
shares at the time of the transfer. For ADR holders electing to receive
ADSs instead of cash, after the 2012 first quarter dividend payment, HM
Revenue & Customs no longer seeks to impose 1.5% stamp duty reserve
tax on issues of UK shares and securities to non-EU clearance services
and depositary receipt systems.
Major shareholders
The disclosure of certain major and significant shareholdings in the share
capital of the company is governed by the Companies Act 2006, the UK
Financial Conduct Authority’s Disclosure Guidance and Transparency
Rules (DTR) and the US Securities Exchange Act of 1934.
Register of members holding bp ordinary shares as at 31 December
2020
Range of holdings
Number of
ordinary
shareholders
52,385
75,742
86,759
10,733
824
674
227,117
Percentage of
total
ordinary
shareholders
23.06
33.35
38.20
4.73
0.36
0.30
100.00
Percentage of
total ordinary
share capital
excluding shares
held in treasury
0.01
0.21
1.36
1.10
1.45
95.87
100.00
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000a
Totals
a Includes JPMorgan Chase Bank, N.A. holding 25.33% of the total ordinary issued share capital
(excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which is
shown in the table below.
Register of holders of American depositary shares (ADSs) as at
31 December 2020a
Range of holdings
Number of
ADS holders
43,236
19,362
10,198
432
7
1
73,236
Percentage of
total ADS holders
59.04
26.44
13.92
0.59
0.01
0.00
100.00
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000b
Totals
a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 1,056,393 approx. underlying shareholders.
As at 31 December 2020 there were also 1,212 preference shareholders.
Preference shareholders represented 0.42% and ordinary shareholders
represented 99.58% of the total issued nominal share capital of the
company (excluding shares held in treasury) as at that date.
Percentage of
total ADSs
0.27
1.07
3.06
0.82
0.22
94.56
100.00
As at 31 December 2020, the company had not received any notifications
pursuant to DTR5. The company also did not receive any notifications
pursuant to DTR5 between 1 January 2021 and 25 February 2021.
Under the US Securities Exchange Act of 1934 bp is aware of the
following interests as at 25 February 2021:
334
bp Annual Report and Form 20-F 2020
« See Glossary
Holder
JPMorgan Chase Bank N.A.,
depositary for ADSs, through its
nominee Guaranty Nominees
Limited
BlackRock, Inc.
The Vanguard Group, Inc
Holding of
ordinary shares
Percentage of
ordinary share
capital excluding
shares held in
treasury
5,098,817,683
1,514,099,140
763,396,544
25.06
7.69
3.75
The company’s major shareholders do not have different voting rights.
The company has also been notified of the following interests in
preference shares as at 25 February 2021:
Holder
The National Farmers Union Mutual
Insurance Society Limited
Hargreaves Lansdown Asset
Management Limited
Interactive Investor Share Dealing
Services
M & G Investment Management Ltd.
Canaccord Genuity Group Inc.
Halifax Share Dealing Services
Holder
The National Farmers Union Mutual
Insurance Society Limited
M & G Investment Management Ltd.
Safra Group
Canaccord Genuity Group Inc.
Holding of 8%
cumulative first
preference shares
Percentage
of class
945,000
13.07
698,778
573,177
528,150
504,162
416,661
9.66
7.92
7.30
6.97
5.76
Holding of 9%
cumulative second
preference shares
Percentage
of class
987,000
644,450
385,000
306,605
18.03
11.77
7.03
5.60
As at 25 February 2021, the total preference shares in issue comprised
only 0.42% of the company’s total issued nominal share capital (excluding
shares held in treasury), the rest being ordinary shares.
Annual general meeting
The 2021 AGM is scheduled to be held on Wednesday 12 May 2021 at
11.00am. A separate notice convening the meeting is distributed to
shareholders, which includes an explanation of the items of business to
be considered at the meeting.
All resolutions for which notice has been given will be decided on a poll.
Deloitte LLP have expressed their willingness to continue in office as
auditors and a resolution for their reappointment is included in the Notice
of bp Annual General Meeting 2021.
Memorandum and Articles of
Association
The following summarizes certain provisions of the company’s
Memorandum and Articles of Association and applicable English law. This
summary is qualified in its entirety by reference to the UK Companies Act
2006 (the Act) and the company’s Memorandum and Articles of
Association. The Memorandum and Articles of Association are available
online at bp.com/usefuldocs.
The company’s Articles of Association may be amended by a special
resolution at a general meeting of the shareholders. At the annual general
meeting (AGM) held on 21 May 2018 shareholders voted to adopt new
Articles of Association to reflect developments in market practice and to
provide clarification and additional flexibility where necessary or
appropriate.
Objects and purposes
Shareholder information
bp is a public company limited by shares, incorporated under the name BP
p.l.c. and is registered in England and Wales with the registered number
102498. The provisions regulating the operations of the company, known
as its ‘objects’, were historically stated in a company’s memorandum. The
Act abolished the need to have object provisions and so at the AGM held
on 15 April 2010 shareholders approved the removal of its objects clause
together with all other provisions of its Memorandum that, by virtue of
the Act, are treated as forming part of the company’s Articles of
Association.
Directors and secretary
The business and affairs of bp shall be managed by the directors. The
company’s Articles of Association provide that directors may be appointed
by the existing directors or by the shareholders in a general meeting. Any
person appointed by the directors will hold office only until the next
general meeting, notice of which is first given after their appointment and
will then be eligible for re-election by the shareholders. A director may be
removed by bp as provided for by applicable law and shall vacate office in
certain circumstances as set out in the Articles of Association. In addition
the company may, by special resolution, remove a director before the
expiration of his/her period of office and, subject to the Articles of
Association, may by ordinary resolution appoint another person to be a
director instead. There is no requirement for a director to retire on
reaching any age.
The Articles of Association place a general prohibition on a director voting
in respect of any contract or arrangement in which the director has a
material interest other than by virtue of such director’s interest in shares
in the company. However, in the absence of some other material interest
not indicated below, a director is entitled to vote and to be counted in a
quorum for the purpose of any vote relating to a resolution concerning the
following matters:
• The giving of security or indemnity with respect to any money lent or
obligation taken by the director at the request or benefit of the
company or any of its subsidiary undertakings.
• Any proposal in which the director is interested, concerning the
underwriting of company securities or debentures or the giving of any
security to a third party for a debt or obligation of the company or any
of its subsidiary undertakings.
• Any proposal concerning any other company in which the director is
interested, directly or indirectly (whether as an officer or shareholder or
otherwise) provided that the director and persons connected with such
director are not the holder or holders of 1% or more of the voting
interest in the shares of such company.
• Any proposal concerning the purchase or maintenance of any insurance
policy under which the director may benefit.
• Any proposal concerning the giving to the director of any other
indemnity which is on substantially the same terms as indemnities
given or to be given to all of the other directors or to the funding by the
company of his expenditure on defending proceedings or the doing by
the company of anything to enable the director to avoid incurring such
expenditure where all other directors have been given or are to be
given substantially the same arrangements.
• Any proposal concerning an arrangement for the benefit of the
employees and directors or former employees and former directors of
the company or any of its subsidiary undertakings, including but
without being limited to a retirement benefits scheme and an
employees’ share scheme, which does not accord to any director any
privilege or advantage not generally accorded to the employees or
former employees to whom the arrangement relates.
The Act requires a director of a company who is in any way interested in a
contract or proposed contract with the company to declare the nature of
the director’s interest at a meeting of the directors of the company. The
definition of ‘interest’ includes the interests of spouses, children,
companies and trusts. The Act also requires that a director must avoid a
situation where a director has, or could have, a direct or indirect interest
that conflicts, or possibly may conflict, with the company’s interests. The
Act allows directors of public companies to authorize such conflicts where
appropriate, if a company’s Articles of Association so permit. bp’s Articles
of Association permit the authorization of such conflicts. The directors
may exercise all the powers of the company to borrow money, except
« See Glossary
bp Annual Report and Form 20-F 2020
335
that the amount remaining undischarged of all moneys borrowed by the
company shall not, without approval of the shareholders, exceed two
times the amount paid up on the share capital plus the aggregate of the
amount of the capital and revenue reserves of the company. Variation of
the borrowing power of the board may only be affected by amending the
Articles of Association.
Remuneration of non-executive directors shall be determined in the
aggregate by resolution of the shareholders. Remuneration of executive
directors is determined by the remuneration committee. This committee
is made up of non-executive directors only. There is no requirement of
share ownership for a director’s qualification.
The Articles of Association provide entitlement to the directors’ pensions
and death and disability benefits to the directors’ relations and
dependants respectively.
The circumstances in which a director’s office will automatically terminate
include: when a director ceases to hold an executive office of the
company and the directors resolve that he should cease to be a director; if
a medical practitioner provides an opinion that a director has become
incapable of acting as a director and may remain so incapable for a further
three months and the directors resolve that he should cease to be a
director; and if all of the other directors vote in favour of a resolution
stating that the person should cease to be a director.
The company secretary has express powers to delegate any of the
powers or discretions conferred on him or her.
Dividend rights; other rights to share in company profits; capital calls
If recommended by the directors of bp, shareholders of bp may, by
resolution, declare dividends but no such dividend may be declared in
excess of the amount recommended by the directors. The directors may
also pay interim dividends without obtaining shareholder approval. No
dividend may be paid other than out of profits available for distribution, as
determined under IFRS and the Act. Dividends on ordinary shares are
payable only after payment of dividends on bp preference shares. Any
dividend unclaimed after a period of 10 years from the date of declaration
of such dividend shall be forfeited and reverts to bp. If the company
exercises its right to forfeit shares and sells shares belonging to an
untraced shareholder then any entitlement to claim dividends or other
monies unclaimed in respect of those shares will be for a period of twelve
months after the sale. The company may take such steps as the directors
decide are appropriate in the circumstances to trace the member entitled
and the sale may be made at such time and on such terms as the
directors may decide.
The directors have the power to declare and pay dividends in any currency
provided that a sterling equivalent is announced. It is not the company’s
intention to change its current policy of paying dividends in US dollars. At
the company’s AGM held on 15 April 2010, shareholders approved the
introduction of a Scrip Dividend Programme (Scrip Programme) and to
include provisions in the Articles of Association to enable the company to
operate the Scrip Programme. The Scrip Programme was renewed at the
company’s AGM held on 21 May 2018 for a further three years. The Scrip
Programme enables ordinary shareholders and bp ADS holders to elect to
receive new fully paid ordinary shares (or bp ADSs in the case of bp ADS
holders) instead of cash. The operation of the Scrip Programme is always
subject to the directors’ decision to make the scrip offer available in
respect of any particular dividend. Should the directors decide not to offer
the scrip in respect of any particular dividend, cash will automatically be
paid instead. The directors may determine in relation to any scrip dividend
plan or programme how the costs of the programme will be met, the
minimum number of ordinary shares required in order to be able to
participate in the programme and any arrangements to deal with legal and
practical difficulties in any particular territory.
Apart from shareholders’ rights to share in bp’s profits by dividend (if any
is declared or announced), the Articles of Association provide that the
directors may set aside:
• A special reserve fund out of the balance of profits each year to make
up any deficit of cumulative dividend on the bp preference shares.
• A general reserve out of the balance of profits each year, which shall be
applicable for any purpose to which the profits of the company may
properly be applied. This may include capitalization of such sum,
pursuant to an ordinary shareholders’ resolution, and distribution to
shareholders as if it were distributed by way of a dividend on the
ordinary shares or in paying up in full unissued ordinary shares for
allotment and distribution as bonus shares.
Any such sums so deposited may be distributed in accordance with the
manner of distribution of dividends as described above.
Holders of shares are not subject to calls on capital by the company,
provided that the amounts required to be paid on issue have been paid
off. All shares are fully paid.
Share transfers and share certificates
The directors may permit transfers to be effected other than by an
instrument in writing and that share certificates will not be required to be
issued by the company if they are not required by law.
The company may charge an administrative fee in the event that a
shareholder wishes to replace two or more certificates representing
shares with a single certificate or wishes to surrender a single certificate
and replace it with two or more certificates. All certificates are sent at the
member’s risk.
Voting rights
The Articles of Association of the company provide that voting on
resolutions at a shareholders’ meeting will be decided on a poll other than
resolutions of a procedural nature, which may be decided on a show of
hands. If voting is on a poll, every shareholder who is present in person or
by proxy has one vote for every ordinary share held and two votes for
every £5 in nominal amount of bp preference shares held. If voting is on a
show of hands, each shareholder who is present at the meeting in person
or whose duly appointed proxy is present in person will have one vote,
regardless of the number of shares held, unless a poll is requested.
Shareholders do not have cumulative voting rights.
For the purposes of determining which persons are entitled to attend or
vote at a shareholders’ meeting and how many votes such persons may
cast, the company may specify in the notice of the meeting a time, not
more than 48 hours before the time of the meeting, by which a person
who holds shares in registered form must be entered on the company’s
register of members in order to have the right to attend or vote at the
meeting or to appoint a proxy to do so.
Holders on record of ordinary shares may appoint a proxy, including a
beneficial owner of those shares, to attend, speak and vote on their
behalf at any shareholders’ meeting, provided that a duly completed proxy
form is received not less than 48 hours (or such shorter time as the
directors may determine) before the time of the meeting or adjourned
meeting or, where the poll is to be taken after the date of the meeting,
not less than 24 hours (or such shorter time as the directors may
determine) before the time of the poll.
Record holders of bp ADSs are also entitled to attend, speak and vote at
any shareholders’ meeting of bp by the appointment by the approved
depositary, JPMorgan Chase Bank N.A., of them as proxies in respect of
the ordinary shares represented by their ADSs. Each such proxy may also
appoint a proxy. Alternatively, holders of bp ADSs are entitled to vote by
supplying their voting instructions to the depositary, who will vote the
ordinary shares represented by their ADSs in accordance with their
instructions.
Proxies may be delivered electronically.
Corporations who are members of the company may appoint one or more
persons to act as their representative or representatives at any
shareholders’ meeting provided that the company may require a corporate
representative to produce a certified copy of the resolution appointing
them before they are permitted to exercise their powers.
Matters are transacted at shareholders’ meetings by the proposing and
passing of resolutions, of which there are two types: ordinary or special.
An ordinary resolution requires the affirmative vote of a majority of the
votes of those persons voting at a meeting at which there is a quorum. A
special resolution requires the affirmative vote of not less than three
quarters of the persons voting at a meeting at which there is a quorum.
Any AGM requires 21 clear days’ notice. The notice period for any other
general meeting is 14 clear days subject to the company obtaining annual
shareholder approval, failing which, a 21 clear day notice period will apply.
336
bp Annual Report and Form 20-F 2020
« See Glossary
Shareholder information
Disclosure of interests in shares
The Act permits a public company to give notice to any person whom the
company believes to be or, at any time during the three years prior to the
issue of the notice, to have been interested in its voting shares requiring
them to disclose certain information with respect to those interests.
Failure to supply the information required may lead to disenfranchisement
of the relevant shares and a prohibition on their transfer and receipt of
dividends and other payments in respect of those shares and any new
shares in the company issued in respect of those shares. In this context
the term ‘interest’ is widely defined and will generally include an interest
of any kind whatsoever in voting shares, including any interest of a holder
of bp ADSs.
Called-up share capital
Details of the allotted, called-up and fully-paid share capital at
31 December 2020 are set out in Financial statements – Note 31. In
accordance with institutional investor guidelines, the company deems it
appropriate to grant authority to the directors to allot shares and other
securities and to disapply pre-emption rights by way of shareholders'
resolutions at each AGM in place of authority granted by virtue of the
company's Articles of Association. At the AGM on 27 May 2020,
authorization was given to the directors to allot shares in the company
and to grant rights to subscribe for, or to convert any
security into, shares in the company up to an aggregate nominal amount
as set out in the Notice of Meeting 2020. These authorities were given for
the period until the next AGM in 2021 or 27 August 2021, whichever is
the earlier. These authorities are renewed annually at the AGM.
Company records and service of notice
In relation to notices not covered by the Act, the reference to notice by
advertisement in a national newspaper also includes advertisements via
other means such as a public announcement.
Liquidation rights; redemption provisions
In the event of a liquidation of bp, after payment of all liabilities and
applicable deductions under UK laws and subject to the payment of
secured creditors, the holders of bp preference shares would be entitled
to the sum of (1) the capital paid up on such shares plus, (2) accrued and
unpaid dividends and (3) a premium equal to the higher of (a) 10% of the
capital paid up on the bp preference shares and (b) the excess of the
average market price over par value of such shares on the LSE during the
previous six months. The remaining assets (if any) would be divided pro
rata among the holders of ordinary shares.
Without prejudice to any special rights previously conferred on the
holders of any class of shares, bp may issue any share with such
preferred, deferred or other special rights, or subject to such restrictions
as the shareholders by resolution determine (or, in the absence of any
such resolutions, by determination of the directors), and may issue shares
that are to be or may be redeemed.
Variation of rights
The rights attached to any class of shares may be varied with the consent
in writing of holders of 75% of the shares of that class or on the adoption
of a special resolution passed at a separate meeting of the holders of the
shares of that class. At every such separate meeting, all of the provisions
of the Articles of Association relating to proceedings at a general meeting
apply, except that the quorum with respect to a meeting to change the
rights attached to the preference shares is 10% or more of the shares of
that class, and the quorum to change the rights attached to the ordinary
shares is one third or more of the shares of that class.
Shareholders’ meetings and notices
Shareholders must provide bp with a postal or electronic address in the
UK to be entitled to receive notice of shareholders’ meetings. Holders of
bp ADSs are entitled to receive notices under the terms of the deposit
agreement relating to bp ADSs. The substance and timing of notices are
described above under the heading Voting rights.
Under the Act, the AGM of shareholders must be held once every year,
within each six month period beginning with the day following the
company’s accounting reference date. All general meetings shall be held
at a time and place determined by the directors. If any shareholders’
meeting is adjourned for lack of quorum, notice of the time and place of
the adjourned meeting may be given in any lawful manner, including
electronically. Powers exist for action to be taken either before or at the
meeting by authorized officers to ensure its orderly conduct and safety of
those attending.
The directors have power to convene a general meeting which is a hybrid
meeting, that is to provide facilities for shareholders to attend a meeting
which is being held at a physical place by electronic means as well (but
not to convene a purely electronic meeting).
The provisions of the Articles of Association in relation to satellite
meetings permit facilities being provided by electronic means to allow
those persons at each place to participate in the meeting.
Limitations on voting and shareholding
There are no limitations, either under the laws of the UK or under the
company’s Articles of Association, restricting the right of non-resident or
foreign owners to hold or vote bp ordinary or preference shares in the
company other than limitations that would generally apply to all of the
shareholders and limitations applicable to certain countries and persons
subject to EU economic sanctions or those sanctions adopted by the UK
government which implement resolutions of the Security Council of the
United Nations.
« See Glossary
bp Annual Report and Form 20-F 2020
337
Purchases of equity securities by the issuer and affiliated purchasers
In November 2017 bp began a share repurchase or buyback programme (the programme). The sole purpose of the programme was to reduce the
issued share capital of the company to offset the ongoing dilutive effect of scrip dividends over time, as announced by the company on 31 October
2017. In January 2020 the share dilution buyback programme had fully offset the impact of scrip dilution since the third quarter 2017. Authorization for
the company to make market purchases (as defined in section 693(4) of the Companies Act 2006) of ordinary shares with a nominal value of $0.25 each
in the company was renewed at the company’s 2020 AGM covering the period until the date of the company's 2021 AGM or 27 August 2021,
whichever is earlier. The maximum number of ordinary shares to be purchased under this authority will not exceed 2,025,610,110 ordinary shares. The
shares purchased will be cancelled.
The following table provides details of ordinary share purchases made (1) under the programme and (2) by the Employee Share Ownership Plans
(ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans.
Number of
shares
purchased by
ESOPs or for
certain
employee share-
based plansb
Number of shares
purchased as part
of the buyback
programmec
Maximun
approximate
dollar value of
shares yet to
be purchased
under the
programme
$ million
Total number of
shares
purchaseda
Average price
paid per share
$
6.47
120,057,464
Nil 120,057,464
2020
January 7 - January 28
February
March
April
May
June
July
August
September
October
November
December
2021
January 11
February (to February 26)
a All share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions.
b Transactions represent the purchases of ADSs made to satisfy requirements of certain employee share-based payment plans.
c The company announced its intent to commence the programme on 31 October 2017 and announced further details and commencement of the programme on 15 November 2017. The programme
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
285,552
285,552
3.98
Nil
Nil
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
was completed in January 2020. At the AGM on 27 May 2020, authorization was given to the company to repurchase up to 2,025,610,110 ordinary shares, for the period ending on the date of the AGM
in 2021 or 27 August 2021, whichever is the earlier. This authorization is renewed annually at the AGM. The total number of ordinary shares repurchased during 2020 under the programme was
120,057,464 at a cost of $776 million (including fees and stamp duty) representing 0.59% of the company’s issued share capital excluding shares held in treasury on 31 December 2020. All ordinary
shares repurchased in 2020 under the programme were cancelled in order to reduce the company’s issued share capital.
338
bp Annual Report and Form 20-F 2020
« See Glossary
Fees and charges payable by ADS holders
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of
withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the
amounts distributed or by selling a portion of the distributable property to pay the fees.
The charges of the Depositary payable by investors are as follows:
Type of service
Depositary actions
Fee
Shareholder information
Depositing or substituting the underlying
shares
Selling or exercising rights
Withdrawing an underlying share
Expenses of the Depositary
Dividend fees
Issuance of ADSs against the deposit of shares,
including deposits and issuances in respect of:
• Share distributions, stock splits, rights, merger.
• Exchange of securities or other transactions or event
or other distribution affecting the ADSs or deposited
securities.
Distribution or sale of securities, the fee being an
amount equal to the fee for the execution and delivery
of ADSs that would have been charged as a result of the
deposit of such securities.
Acceptance of ADSs surrendered for withdrawal of
deposited securities.
Expenses incurred on behalf of holders in connection
with:
• Stock transfer or other taxes and governmental
charges.
• Delivery by cable, telex, electronic and facsimile
transmission.
• Transfer or registration fees, if applicable, for the
registration of transfers of underlying shares.
• Expenses of the Depositary in connection with the
conversion of foreign currency into US dollars (which
are paid out of such foreign currency).
ADS holders who receive a cash dividend are charged a
fee which bp uses to offset the costs associated with
administering the ADS programme.
Global Invest Direct (GID) Plan
New investors and existing ADS holders can buy, sell or
reinvest dividends into further bp ADSs by enrolling in
bp’s GID Plan, sponsored and administered by the
Depositary.
$5.00 per 100 ADSs (or portion thereof)
evidenced by the new ADSs delivered.
$5.00 per 100 ADSs (or portion thereof).
$5.00 for each 100 ADSs (or portion thereof)
evidenced by the ADSs surrendered.
Expenses payable are subject to agreement
between the company and the Depositary by
billing holders or by deducting charges from one
or more cash dividends or other cash
distributions.
The Deposit Agreement provides that a fee of
$0.05 or less per ADS can be charged. The
current fee is $0.02 per bp ADS per calendar
year (equivalent to $0.005 per bp ADS per
quarter per cash distribution).
Cost per transaction is $2.00 for recurring, $2.00
for one-time automatic investments, and $5.00
for investment made by check. Dividend
reinvestment is 5% of the dividend amount up to
a maximum of $5.00. Purchase trading
commission is $0.12 per share.
Fees and payments made by the
Depositary to the issuer
The Depositary has agreed to reimburse certain company expenses
related to the company’s ADS programme and incurred by the company
in connection with the ADS programme arising during the year ended
31 December 2020. The Depositary reimbursed to the company, or paid
amounts on the company’s behalf to third parties, or waived its fees and
expenses, of $18,936,081.43 for the year ended 31 December 2020.
The table below sets out the types of expenses that the Depositary has
agreed to reimburse and the fees it has agreed to waive for standard
costs associated with the administration of the ADS programme relating
to the year ended 31 December 2020.
Category of expense reimbursed,
waived or paid directly to third parties
Amount reimbursed, waived or
paid directly to third parties for the
year ended 31 December 2020
Fees for delivery and surrender of bp
ADSs
Dividend feesa
Total
a Dividend fees are charged to ADS holders who receive a cash distribution, which bp uses to
1,267,682.60
17,668,398.83
18,936,081.43
expenses paid to or on behalf of the company during the 12-month period
prior to notice of removal or termination.
Documents on display
The bp Annual Report and Form 20-F 2020 is available online at bp.com/
annualreport. To obtain a hard copy of bp’s complete audited financial
statements, free of charge, UK based shareholders should contact bp
Distribution Services by calling +44 (0) 800 037 2172 or by emailing
bpdistributionservices@bp.com. If based in the US or Canada
shareholders should contact Issuer Direct by calling +1 888 301 2505 or
by emailing bpreports@issuerdirect.com.
The company is subject to the information requirements of the US
Securities Exchange Act of 1934 applicable to foreign private issuers. In
accordance with these requirements, the company files its Annual Report
and Form 20-F and other related documents with the SEC. The SEC
maintains an internet site at www.sec.gov that contains reports and other
information regarding issuers, including bp, that file electronically with the
SEC. bp's SEC filings are also available at bp.com/sec. bp discloses in this
report (see Corporate governance practices (Form 20-F Item 16G) on page
326) significant ways (if any) in which its corporate governance practices
differ from those mandated for US companies under NYSE listing
standards.
offset the costs associated with administering the ADS programme.
Under certain circumstances, including removal of the Depositary or
termination of the ADR programme by the company, the company is
required to repay the Depositary certain amounts reimbursed and/or
« See Glossary
bp Annual Report and Form 20-F 2020
339
Shareholding administration
If you have any queries about the administration of shareholdings, such as
change of address, change of ownership, dividend payment options or to
change the way you receive your company documents (such as the bp
Annual Report and Form 20-F and Notice of bp Annual General Meeting)
please contact the bp Registrar or the bp ADS Depositary.
Ordinary and preference shareholders
The bp Registrar, Link Group, Central Square,
29 Wellington Street,
Leeds, LS1 4DL
Freephone in UK 0800 701107
From outside the UK +44 (0)371 277 1014
ADS holders
bp Shareowner Services
PO Box 64504, St Paul, MN 55164-0504, US
Toll-free in US and Canada +1 877 638 5672
From outside the US and Canada +1 651 306 4383
2021 shareholder calendara
26 Mar 2021
Fourth quarter interim dividend payment for 2020
27 April 2021 First quarter results announced
7 May 2021
Record date (to be eligible for the first quarter interim
dividend)
12 May 2021 Annual general meeting
18 Jun 2021
First quarter interim dividend payment for 2021
2 Jul 2021
8% and 9% preference shares record date
27 Jul 2021
Second quarter results announced
30 Jul 2021
6 Aug 2021
8% and 9% preference shares dividend payment
Record date (to be eligible for the second quarter interim
dividend)
24 Sep 2021
Second quarter interim dividend payment for 2021
2 Nov 2021
12 Nov 2021 Record date (to be eligible for the third quarter interim
Third quarter results announced
dividend)
17 Dec 2021
Third quarter interim dividend payment for 2021
a All future dates are provisional and may be subject to change. For the full calendar see bp.com/
financialcalendar.
340
bp Annual Report and Form 20-F 2020
« See Glossary
Glossary
Abbreviations
ADR
American depositary receipt.
ADS
American depositary share. 1 ADS = 6 ordinary shares.
Barrel (bbl)
159 litres, 42 US gallons.
bcf
Billion cubic feet.
bcfe
Billion cubic feet equivalent.
EVP
Executive vice president.
FPSO
Floating production, storage and offloading.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
gCO2e/MJ
Grams of carbon dioxide equivalent per megajoule of energy.
GHG
Greenhouse gas.
GRI
Global Reporting Initiative.
GtCO2
Gigatonnes of carbon dioxide.
GWh
Gigawatt hour.
HSSE
Health, safety, security and environment.
IFRS
International Financial Reporting Standards.
Kb/d
Thousand barrels per day.
KPIs
Key performance indicators.
kt
Thousand tonnes.
LNG
Liquefied natural gas.
LPG
Liquefied petroleum gas.
mb/d
Thousand barrels per day.
Mbbl
Million barrels.
mboe/d
Thousand barrels of oil equivalent per day.
mmb/d
Million barrels per day.
mmboe/d
Million barrels of oil equivalent per day.
mmBtu
Million British thermal units.
mmcf/d
Million cubic feet per day.
Mte
Million tonnes.
MteCO2e
Million tonnes of CO2 equivalent.
Mtpa
Million tonnes per annum.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
PTA
Purified terephthalic acid.
RC
Replacement cost.
SEC
The United States Securities and Exchange Commission.
TWh
Terawatt hour.
SVP
Senior vice president.
Definitions
Unless the context indicates otherwise, the definitions for the following
glossary terms are given below.
Non-GAAP measures are sometimes referred to as alternative
performance measures.
CA100+ resolution glossary
CA100+ resolution
The CA100+ resolution means the special resolution requisitioned by
Climate Action 100+ and passed at bp’s 2019 Annual General Meeting,
the text of which is set out below.
Special resolution: Climate Action 100+ shareholder resolution on
climate change disclosures.
That in order to promote the long term success of the company, given the
recognised risks and opportunities associated with climate change, we as
shareholders direct the company to include in its strategic report and/or
other corporate reports, as appropriate, for the year ending 2019 onwards,
a description of its strategy which the board considers, in good faith, to be
consistent with the goals of Articles 2.1(a)(1) and 4.1(2) of the Paris
Agreement(3) (the ‘Paris goals’), as well as:
(1) Capital expenditure: how the company evaluates the consistency of
each new material capex investment, including in the exploration,
acquisition or development of oil and gas resources and reserves and
other energy sources and technologies, with (a) the Paris goals and
separately (b) a range of other outcomes relevant to its strategy.
(2) Metrics and targets: the company’s principal metrics and relevant
targets or goals over the short, medium and/or long-term, consistent
with the Paris goals, together with disclosure of:
a. The anticipated levels of investment in (i) oil and gas resources and
reserves; and (ii) other energy sources and technologies.
b. The company’s targets to promote reductions in its operational
greenhouse gas emissions, to be reviewed in line with changing
protocols and other relevant factors
c. The estimated carbon intensity of the company’s energy products
bp Annual Report and Form 20-F 2020
341
and progress on carbon intensity over time.
d. Any linkage between the above targets and executive
remuneration.
(3) Progress reporting: an annual review of progress against (1) and (2)
above.
Such disclosure and reporting to include the criteria and summaries of the
methodology and core assumptions used, and to omit commercially
confidential or competitively sensitive information and be prepared at
reasonable cost; and provided that nothing in this resolution shall limit the
company’s powers to set and vary its strategy, or associated targets or
metrics, or to take any action which it believes in good faith, would best
promote the long-term success of the company.
The Paris goals
(1) Article 2.1(a) of the Paris Agreement states the goal of ‘Holding the
increase in the global average temperature to well below 2°C above
pre-industrial levels and pursuing efforts to limit the temperature
increase to 1.5°C above pre-industrial levels, recognizing that this
would significantly reduce the risks and impacts of climate change’.
(2) Article 4.1 of the Paris Agreement: In order to achieve the long-term
temperature goal set out in Article 2, parties aim to reach global
peaking of greenhouse gas emissions as soon as possible,
recognizing that peaking will take longer for developing country
parties, and to undertake rapid reductions thereafter in accordance
with best available science, so as to achieve a balance between
anthropogenic emissions by sources and removals by sinks of
greenhouse gases in the second half of this century, on the basis of
equity, and in the context of sustainable development and efforts to
eradicate poverty.
(3) U.N. Framework Convention on Climate Change Conference of
Parties, Twenty-First Session, Adoption of the Paris Agreement, U.N.
Doc. FCCC/CP/2015/L.9/Rev.1 (Dec. 12, 2015).
New material capex investment
For the purposes of the 2020 evaluation discussed on pages 28-32, ‘new
material capex investment’ means a decision taken by the resource
commitment meeting (RCM) in 2020 to incur inorganic or organic
investments greater than $250 million that relate to a new project or
asset, extending an existing project or asset, or acquiring or increasing a
share in a project, asset or entity.
There were three investments that met the above criteria in 2020.
Material capex evaluation: Paris-consistency quantitative tests.
For the purposes of evaluating material capex investments for
consistency with the Paris goals, two quantitative tests were applied, see
page 32.
1. Operational carbon intensity (CI)
The annual average operational GHG emissions (TeCO2e/unit), divided
by the relevant unit of output:
• per thousand barrels of oil equivalent in Upstream
• per utilized equivalent distillation capacity in refining
• per thousand tonnes in petrochemicals.
Net zero aims and ambition glossary
Net zero
References to global net zero in the phrase, 'to help the world get to net
zero', means achieving '...a balance between anthropogenic emissions by
sources and removals by sinks of greenhouse gases...on the basis of
equity, and in the context of sustainable development and efforts to
eradicate poverty', as set out in Article 4(1) of the Paris Agreement.
References to net zero for bp in the context of our ambition and Aims 1
and 2 as set out on page 49 (such as 'be a net zero company by 2050 or
sooner'), means achieving a balance between (a) the relevant Scope 1 and
2 emissions (for our Aim 1), or Scope 3 emissions (for our Aim 2), and (b)
the aggregate of applicable deductions from qualifying activities such as
sinks under our methodology at the applicable time.
Emissions from the carbon in our Upstream oil and gas production
Estimated CO2 emissions from the combustion of upstream production of
crude oil, natural gas and natural gas liquids (NGLs) on a bp equity-share
basis based on bp’s net share of production, excluding bp’s share of
Rosneft production and assuming that all produced volumes undergo full
stoichiometric combustion to CO2.
Average emissions intensity of marketed energy products
The weighted average GHG emissions per unit of energy delivered (in
grams CO2e/MJ), estimated in respect of marketing sales of energy
products. GHG emissions are estimated on a lifecycle basis covering
production, distribution and use of the relevant products (assuming full
stoichiometric combustion of the product to CO2).
Methane intensity
Methane intensity refers to the amount of methane emissions from bp’s
operated upstream oil and gas assets as a percentage of the total gas that
goes to market from those operations. Our methodology is aligned with
the Oil and Gas Climate Initiative’s (OGCI).
Sustainable emissions reductions (SER)
SERs result from actions or interventions that have led to ongoing
reductions in Scope 1 (direct) and/or Scope 2 (indirect) greenhouse gas
(GHG) emissions (carbon dioxide and methane) such that GHG emissions
would have been higher in the reporting year if the intervention had not
taken place. SERs must meet three criteria: a specific intervention that
has reduced GHG emissions, the reduction must be quantifiable and the
reduction is expected to be ongoing. Reductions are reportable for a 12-
month period from the start of the intervention/action.
Adjusted EBIDA
Non-GAAP measure. Adjusted EBIDA is defined as underlying
replacement cost profit before interest and tax, add back depreciation,
depletion and amortization and exploration expenditure written-off (net of
non-operating items), less taxation on an underlying RC basis. bp believes
that adjusted EBIDA is a useful measure for investors because it is a
measure closely tracked by management to evaluate bp’s operating
performance and to make financial, strategic and operating decisions and
because it may help investors to understand and evaluate, in the same
manner as management, the underlying trends in bp’s operational
performance on a comparable basis, period on period. The nearest
equivalent measure on an IFRS basis is profit or loss before interest and
tax. Adjusted EBIDA per share is calculated based on the shares in issue
at period-end.
Adjusted effective tax rate (ETR)
Non-GAAP measure. The adjusted ETR is calculated by dividing taxation
on an underlying replacement cost (RC) basis excluding the impact of
reductions in the rate of the UK North Sea supplementary charge in 2016
by underlying RC profit or loss before tax. Taxation on an underlying RC
basis is taxation on a RC basis for the period adjusted for taxation on non-
operating items and fair value accounting effects, and certain foreign
exchange impacts on the group’s tax charge for the period. Information
on underlying RC profit or loss is provided below. bp believes it is helpful
to disclose the adjusted ETR because this measure may help investors to
understand and evaluate, in the same manner as management, the
underlying trends in bp’s operational performance on a comparable basis,
period on period. The nearest equivalent measure on an IFRS basis is the
ETR on profit or loss for the period. A reconciliation to GAAP information
is provided on page 348.
Associate
An entity over which the group has significant influence and that is neither
a subsidiary nor a joint arrangement of the group. Significant influence is
the power to participate in the financial and operating policy decisions of
the investee but is not control or joint control over those policies.
Bioenergy production
Bioenergy production is average thousands of barrels of biofuel
production per day during the period covered, net to bp. This includes
equivalent ethanol production, bp Bunge biopower for grid export, biogas
and refining co-processing and standalone hydrogenated vegetable oil
(HVO).
342
bp Annual Report and Form 20-F 2020
Brent
A trading classification for North Sea crude oil that serves as a major
benchmark price for purchases of oil worldwide.
Capital expenditure
Total cash capital expenditure as stated in the group cash flow statement.
Castrol sales and other operating revenues
Castrol sales and other operating revenues, are sales and other operating
revenues generated by our Castrol business.
Commodity trading contracts
bp participates in regional and global commodity trading markets in order
to manage, transact and hedge the crude oil, refined products and natural
gas that the group either produces or consumes in its manufacturing
operations. The range of contracts the group enters into in its commodity
trading operations is described below. Using these contracts, in
combination with rights to access storage and transportation capacity,
allows the group to access advantageous pricing differences between
locations, time periods and grades.
Exchange-traded commodity derivatives
Contracts that are typically in the form of futures and options traded on a
recognized exchange, such as Nymex and ICE. Such contracts are traded
in standard specifications for the main marker crude oils, such as Brent
and West Texas Intermediate; the main product grades, such as gasoline
and gasoil; and for natural gas and power. Gains and losses, otherwise
referred to as variation margin, are generally settled on a daily basis with
the relevant exchange. These contracts are used for the trading and risk
management of crude oil, refined products, and natural gas and power.
Realized and unrealized gains and losses on exchange-traded commodity
derivatives are included in sales and other operating revenues for
accounting purposes.
Over-the-counter (OTC) contracts
Contracts that are typically in the form of forwards, swaps and options.
Some of these contracts are traded bilaterally between counterparties or
through brokers, others may be cleared by a central clearing counterparty.
These contracts can be used both for trading and risk management
activities. Realized and unrealized gains and losses on OTC contracts are
included in sales and other operating revenues for accounting purposes.
Many grades of crude oil bought and sold use standard contracts
including US domestic light sweet crude oil, commonly referred to as
West Texas Intermediate, and a standard North Sea crude blend – Brent,
Forties, Oseberg and Ekofisk (BFOE). Forward contracts are used in
connection with the purchase of crude oil supplies for refineries and for
marketing and sales of the group’s oil production and refined products.
The contracts typically contain standard delivery and settlement terms.
These transactions call for physical delivery of oil with consequent
operational and price risk. However, various means exist and are used
from time to time, to settle obligations under the contracts in cash rather
than through physical delivery. Physically settled BFOE contracts
delivered by cargo additionally specify a standard volume and tolerance.
Gas and power OTC markets are highly developed in North America and
the UK, where commodities can be bought and sold for delivery in future
periods. These contracts are negotiated between two parties to purchase
and sell gas and power at a specified price, with delivery and settlement
at a future date. Typically, the contracts specify delivery terms for the
underlying commodity. Some of these transactions are not settled
physically as they can be net settled by transacting offsetting sale or
purchase contracts for the same location and delivery period. The
contracts contain standard terms such as delivery point, pricing
mechanism, settlement terms and specification of the commodity.
Typically, volume, price and term (e.g. daily, monthly and balance of
month) are the main variable contract terms.
Swaps are typically contractual obligations to exchange cash flows
between two parties. A typical swap transaction usually references a
floating price and a fixed price with the net difference of the cash flows
being settled. Options give the holder the right, but not the obligation, to
buy or sell crude, oil products, natural gas or power at a specified price on
or before a specific future date. Amounts under these derivative financial
instruments are settled at expiry. Typically, netting agreements are used
to limit credit exposure and support liquidity.
Spot and term contracts
Spot contracts are contracts to purchase or sell a commodity at the
market price prevailing on or around the delivery date when title to the
inventory is taken. Term contracts are contracts to purchase or sell a
commodity at regular intervals over an agreed term. Though spot and
term contracts may have a standard form, there is no offsetting
mechanism in place. As such, these transactions result in physical
delivery with operational and price risk. Spot and term contracts typically
relate to purchases of crude for a refinery, products for marketing, or
third-party natural gas, or sales of the group’s oil production, oil products
or gas production to third parties. For accounting purposes, spot and term
sales are included in sales and other operating revenues when title
passes. Similarly, spot and term purchases are included in purchases for
accounting purposes.
Consolidation adjustment – UPII
Unrealized profit in inventory arising on inter-segment transactions.
Convenience gross margin
Non-GAAP measure. Convenience gross margin comprises store gross
margin as well as other merchandise and service contribution, not
considered as retail fuels or store gross margin, received from the retail
service stations operated under a bp brand, excluding equity-accounted
entities.
Convenience, retail fuels and electrification gross margin
Non-GAAP measure. Convenience, retail fuels and electrification gross
margin is RC profit before interest and tax for Downstream, adjusted for
non-operating items and fair value accounting effects to derive underlying
RC profit before interest and tax. Downstream underlying RC profit before
interest and tax is further adjusted by subtracting underlying RC profit
before interest and tax for the petrochemicals, refining and trading and
lubricants businesses; adding-back depreciation, depletion and
amortization, production and manufacturing, distribution and
administration expenses for fuels (excluding refining and trading);
subtracting earnings from equity-accounted entities in fuels (excluding
refining and trading) and gross margin for aviation, B2B and midstream
businesses.
Margin share for convenience and electrification is the ratio of
convenience and electrification gross margin to total consumer energy
(retail fuels and electrification) and convenience gross margin.
bp believes it is helpful to disclose the margin share from convenience
and electrification because this measure may help investors to
understand and evaluate, in the same way as management, our progress
against our strategic objectives of redefining convenience and scaling up
our next-gen mobility solutions. The nearest GAAP measures of the
numerator and denominator are RC profit before interest and tax. A
reconciliation to GAAP information is provided on page 318.
We are unable to present forward-looking information of the nearest
GAAP measures of the numerator and denominator for margin share for
convenience and electrification, because without unreasonable efforts,
we are unable to forecast accurately certain adjusting items required to
calculate a meaningful comparable GAAP forward-looking financial
measure. These items include inventory holding gains or losses, that is
difficult to predict in advance in order to include in a GAAP estimate.
Cumulative cash costs reductions
Non-GAAP measure. Cash costs are a subset of production and
manufacturing expenses plus distribution and administration expenses
and they exclude costs that are classified as non-operating items. They
represent the substantial majority of the remaining expenses in these line
items but exclude certain costs that are variable, primarily with volumes
(such as freight costs). Management believes that cash costs is a
performance measure that provides investors with useful information
regarding the company’s financial performance, because it considers
these expenses to be the principal operating and overhead expenses that
are most directly under their control although they also include certain
foreign exchange and commodity price effects. Cumulative cash cost
reductions in 2021 compared to 2019, as applicable to the directors’
remuneration usage, are further defined as 2021 exit rate, less agreed
portfolio changes compared to 2019 baseline.
bp Annual Report and Form 20-F 2020
343
Customer touchpoints
Customer touchpoints are the number of retail customer transactions per
day on bp forecourts globally. These include transactions involving fuel
and/or convenience across all channels of trade.
Developed renewables to final investment decision (FID)
Total generating capacity for assets developed to FID by all entities where
bp has an equity share (proportionate to equity share). If asset is
subsequently sold bp will continue to record capacity as developed to FID.
If bp equity share increases developed capacity to FID will increase
proportionately to share increase for any assets where bp held equity at
the point of FID.
Divestment proceeds
Disposal proceeds as per the group cash flow statement.
Dividend yield
Sum of the four quarterly dividends announced in respect of the year as a
percentage of the year-end share price.
Effective tax rate (ETR) on replacement cost (RC) profit or loss
Non-GAAP measure. The ETR on RC profit or loss is calculated by dividing
taxation on a RC basis by RC profit or loss before tax. Information on RC
profit or loss is provided below. bp believes it is helpful to disclose the
ETR on RC profit or loss because this measure excludes the impact of
price changes on the replacement of inventories and allows for more
meaningful comparisons between reporting periods. The nearest
equivalent measure on an IFRS basis is the ETR on profit or loss for the
period. A reconciliation to GAAP information is provided on page 348.
Electric vehicle charge points
Defined as charge points operated by either bp or a bp joint venture.
Fair value accounting effects
Non-GAAP adjustments to our IFRS profit or loss. We use derivative
instruments to manage the economic exposure relating to inventories
above normal operating requirements of crude oil, natural gas and
petroleum products. Under IFRS, these inventories are recorded at
historical cost. The related derivative instruments, however, are required
to be recorded at fair value with gains and losses recognized in the
income statement. This is because hedge accounting is either not
permitted or not followed, principally due to the impracticality of
effectiveness-testing requirements. Therefore, measurement differences
in relation to recognition of gains and losses occur. Gains and losses on
these inventories are not recognized until the commodity is sold in a
subsequent accounting period. Gains and losses on the related derivative
commodity contracts are recognized in the income statement, from the
time the derivative commodity contract is entered into, on a fair value
basis using forward prices consistent with the contract maturity.
bp enters into physical commodity contracts to meet certain business
requirements, such as the purchase of crude for a refinery or the sale of
bp’s gas production. Under IFRS these physical contracts are treated as
derivatives and are required to be fair valued when they are managed as
part of a larger portfolio of similar transactions. Gains and losses arising
are recognized in the income statement from the time the derivative
commodity contract is entered into.
IFRS require that inventory held for trading is recorded at its fair value
using period-end spot prices, whereas any related derivative commodity
instruments are required to be recorded at values based on forward prices
consistent with the contract maturity. Depending on market conditions,
these forward prices can be either higher or lower than spot prices,
resulting in measurement differences.
bp enters into contracts for pipelines and other transportation, storage
capacity, oil and gas processing and liquefied natural gas (LNG) that,
under IFRS, are recorded on an accruals basis. These contracts are risk-
managed using a variety of derivative instruments that are fair valued
under IFRS. This results in measurement differences in relation to
recognition of gains and losses.
The way that bp manages the economic exposures described above, and
measures performance internally, differs from the way these activities are
measured under IFRS. bp calculates this difference for consolidated
entities by comparing the IFRS result with management’s internal
measure of performance. Under management’s internal measure of
performance the inventory, transportation and capacity contracts in
344
bp Annual Report and Form 20-F 2020
question are valued based on fair value using relevant forward prices
prevailing at the end of the period. The fair values of derivative
instruments used to risk manage certain oil, gas and other contracts, are
deferred to match with the underlying exposure and the commodity
contracts for business requirements are accounted for on an accruals
basis. We believe that disclosing management’s estimate of this
difference provides useful information for investors because it enables
investors to see the economic effect of these activities as a whole.
Fair value accounting effects also include changes in the fair value of the
near-term portions of LNG contracts that fall within bp’s risk management
framework. LNG contracts are not considered derivatives, because there
is insufficient market liquidity, and they are therefore accrual accounted
under IFRS. However, oil and natural gas derivative financial instruments
(used to risk manage the near-term portions of the LNG contracts) are fair
valued under IFRS. The fair value accounting effect reduces timing
differences between recognition of the derivative financial instruments
used to risk manage the LNG contracts and the recognition of the LNG
contracts themselves, which therefore gives a better representation of
performance in each period.
In addition, from 2020 fair value accounting effects include changes in the
fair value of derivatives entered into by the group to manage currency
exposure and interest rate risks relating to hybrid bonds to their
respective first call periods. The hybrid bonds which were issued on 17
June 2020 are classified as equity instruments and were recorded in the
balance sheet at that date at their USD equivalent issued value. Under
IFRS these equity instruments are not remeasured from period to period,
and do not qualify for application of hedge accounting. The derivative
instruments relating to the hybrid bonds, however, are required to be
recorded at fair value with mark to market gains and losses recognized in
the income statement. Therefore, measurement differences in relation to
the recognition of gains and losses occur. The fair value accounting effect,
which is reported in the Other businesses and corporate segment,
eliminates the fair value gains and losses of these derivative financial
instruments that are recognized in the income statement. We believe that
this gives a better representation of performance, by more appropriately
reflecting the economic effect of these risk management activities, in
each period.
Finance debt ratio
Finance debt ratio is defined as the ratio of finance debt to the total of
finance debt plus total equity.
Free cash flow
Operating cash flow less net cash used in investing activities and lease
liability payments included in financing activities, as presented in the
group cash flow statement.
Gearing and net debt
Non-GAAP measures. Net debt is calculated as finance debt, as shown in
the balance sheet, plus the fair value of associated derivative financial
instruments that are used to hedge foreign currency exchange and
interest rate risks relating to finance debt, for which hedge accounting is
applied, less cash and cash equivalents. Gearing is defined as the ratio of
net debt to the total of net debt plus total equity. bp believes these
measures provide useful information to investors. Net debt enables
investors to see the economic effect of finance debt, related hedges and
cash and cash equivalents in total. Gearing enables investors to see how
significant net debt is relative to total equity. The derivatives are reported
on the balance sheet within the headings ‘Derivative financial
instruments’. See Financial statements – Note 27 for information on
finance debt, which is the nearest equivalent measure to net debt on an
IFRS basis. The nearest equivalent GAAP measure to gearing on an IFRS
basis is finance debt ratio.
We are unable to present reconciliations of forward-looking information
for gearing to finance debt ratio, because without unreasonable efforts,
we are unable to forecast accurately certain adjusting items required to
present a meaningful comparable GAAP forward-looking financial
measure. These items include fair value asset (liability) of hedges related
to finance debt and cash and cash equivalents, that are difficult to predict
in advance in order to include in a GAAP estimate.
Gearing including leases and net debt including leases
Non-GAAP measure. Net debt including leases is calculated as net debt
plus lease liabilities, less the net amount of partner receivables and
payables relating to leases entered into on behalf of joint operations.
Gearing including leases is defined as the ratio of net debt including
leases to the total of net debt including leases plus total equity. bp
believes these measures provide useful information to investors as they
enable investors to understand the impact of the group’s lease portfolio
on net debt and gearing. See Financial statements – Note 27 for
information on finance debt, which is the nearest equivalent measure to
net debt including leases on an IFRS basis. The nearest equivalent GAAP
measure to gearing including leases on an IFRS basis is finance debt ratio.
Henry Hub
A distribution hub on the natural gas pipeline system in Erath, Louisiana,
that lends its name to the pricing point for natural gas futures contracts
traded on the New York Mercantile Exchange and the over-the-counter
swaps traded on Intercontinental Exchange.
Hydrocarbons
Liquids and natural gas. Natural gas is converted to oil equivalent at
5.8 billion cubic feet = 1 million barrels.
Inorganic capital expenditure
A subset of capital expenditure on a cash basis and is a non-GAAP
measure. Inorganic capital expenditure comprises consideration in
business combinations and certain other significant investments made by
the group. It is reported on a cash basis. bp believes that this measure
provides useful information as it allows investors to understand how bp’s
management invests funds in projects which expand the group’s activities
through acquisition. Further information and a reconciliation to GAAP
information is provided on page 303.
Inventory holding gains and losses
The difference between the cost of sales calculated using the
replacement cost of inventory and the cost of sales calculated on the first-
in first-out (FIFO) method after adjusting for any changes in provisions
where the net realizable value of the inventory is lower than its cost.
Under the FIFO method, which we use for IFRS reporting, the cost of
inventory charged to the income statement is based on its historical cost
of purchase or manufacture, rather than its replacement cost. In volatile
energy markets, this can have a significant distorting effect on reported
income. The amounts disclosed represent the difference between the
charge to the income statement for inventory on a FIFO basis (after
adjusting for any related movements in net realizable value provisions)
and the charge that would have arisen based on the replacement cost of
inventory. For this purpose, the replacement cost of inventory is
calculated using data from each operation’s production and manufacturing
system, either on a monthly basis, or separately for each transaction
where the system allows this approach. The amounts disclosed are not
separately reflected in the financial statements as a gain or loss. No
adjustment is made in respect of the cost of inventories held as part of a
trading position and certain other temporary inventory positions. See
Replacement cost (RC) profit or loss definition below.
Joint arrangement
An arrangement in which two or more parties have joint control.
Joint control
Contractually agreed sharing of control over an arrangement, which exists
only when decisions about the relevant activities require the unanimous
consent of the parties sharing control.
Joint operation
A joint arrangement whereby the parties that have joint control of the
arrangement have rights to the assets, and obligations for the liabilities,
relating to the arrangement.
Joint venture
A joint arrangement whereby the parties that have joint control of the
arrangement have rights to the net assets of the arrangement.
Liquids
Comprises crude oil, condensate and natural gas liquids. For the
Upstream segment, it also includes bitumen.
LNG portfolio
LNG portfolio refers to bp group’s LNG equity production plus additional
long-term merchant LNG volumes.
LNG train
An LNG train is a processing facility used to liquefy and purify natural gas
in the formation of LNG.
Low carbon energy / low carbon technologies
Low carbon (renewable) electricity; bio-energy; electrification; future
mobility solutions; carbon capture, use and storage (CCUS); “blue” or
“green” hydrogen; and trading in low carbon products. Note that, while
there is some overlap, these terms do not mean the same as bp’s
strategic focus area of “low carbon electricity and energy”.
Low carbon investment / investment in low carbon energy /
investment in low carbon
Capital expenditure on low carbon energy or technologies.
Low carbon and other energy transition activities
Low carbon energy / technologies as described above, together with
convenience; integrated gas and power; bp Ventures and Launchpad.
Major projects
Have a bp net investment of at least $250 million, or are considered to be
of strategic importance to bp or of a high degree of complexity.
Margin share for convenience and electrification
Non-GAAP measure. See Convenience, retail fuels and electrification
gross margin definition.
Non-operating items
Charges and credits are included in the financial statements that bp
discloses separately because it considers such disclosures to be
meaningful and relevant to investors. They are items that management
considers not to be part of underlying business operations and are
disclosed in order to enable investors better to understand and evaluate
the group’s reported financial performance. Non-operating items within
equity-accounted earnings are reported net of incremental income tax
reported by the equity-accounted entity. An analysis of non-operating
items by segment and type is shown on page 304.
Operating cash flow
Net cash provided by (used in) operating activities as stated in the group
cash flow statement. When used in the context of a segment rather than
the group, the terms refer to the segment’s share thereof.
Operating cash flow excluding Gulf of Mexico oil spill payments
Non-GAAP measure. It is calculated by excluding post-tax operating cash
flows relating to the Gulf of Mexico oil spill from net cash provided by
operating activities as reported in the group cash flow statement. bp
believes net cash provided by operating activities excluding amounts
related to the Gulf of Mexico oil spill is a useful measure as it allows for
more meaningful comparisons between reporting periods. The nearest
equivalent measure on an IFRS basis is net cash provided by operating
activities.
Operating management system (OMS)
bp’s OMS helps us manage risks in our operating activities by setting out
bp’s principles for good operating practice. It brings together bp
requirements on health, safety, security, the environment, social
responsibility and operational reliability, as well as related issues, such as
maintenance, contractor relations and organizational learning, into a
common management system.
Organic capital expenditure
A subset of capital expenditure on a cash basis and is a non-GAAP
measure. Organic capital expenditure comprises capital expenditure less
inorganic capital expenditure. bp believes that this measure provides
useful information as it allows investors to understand how bp’s
management invests funds in developing and maintaining the group’s
assets. An analysis of organic capital expenditure by segment and region,
and a reconciliation to GAAP information is provided on page 303.
We are unable to present reconciliations of forward-looking information
for organic capital expenditure to total cash capital expenditure, because
without unreasonable efforts, we are unable to forecast accurately the
bp Annual Report and Form 20-F 2020
345
adjusting item, inorganic capital expenditure, that is difficult to predict in
advance in order to derive the nearest GAAP estimate.
shareholders. See Financial statements – Note 5. A reconciliation to GAAP
information is provided on page 302.
Production-sharing agreement / contract (PSA / PSC)
An arrangement through which an oil and gas company bears the risks
and costs of exploration, development and production. In return, if
exploration is successful, the oil company receives entitlement to variable
physical volumes of hydrocarbons, representing recovery of the costs
incurred and a stipulated share of the production remaining after such
cost recovery.
Readily marketable inventory (RMI)
RMI is inventory held and price risk-managed by our integrated supply and
trading function (IST) which could be sold to generate funds if required. It
comprises oil and oil products for which liquid markets are available and
excludes inventory which is required to meet operational requirements
and other inventory which is not price risk-managed. RMI is reported at
fair value. Inventory held by the Downstream fuels business for the
purpose of sales and marketing, and all inventories relating to the
lubricants and petrochemicals businesses, are not included in RMI. bp
believes that disclosing the amounts of RMI and paid-up RMI is useful to
investors as it enables them to better understand and evaluate the
group’s inventories and liquidity position by enabling them to see the level
of discretionary inventory held by IST and to see builds or releases of
liquid trading inventory.
Paid-up RMI excludes RMI which has not yet been paid for. For inventory
that is held in storage, a first-in first-out (FIFO) approach is used to
determine whether inventory has been paid for or not. Unpaid RMI is RMI
which has not yet been paid for by bp. RMI at fair value, Paid-up RMI and
Unpaid RMI are non-GAAP measures. A reconciliation of total inventory as
reported on the group balance sheet to paid-up RMI is provided on page
349.
Realizations
Realizations are the result of dividing revenue generated from
hydrocarbon sales, excluding revenue generated from purchases made
for resale and royalty volumes, by revenue generating hydrocarbon
production volumes. Revenue generating hydrocarbon production reflects
the bp share of production as adjusted for any production which does not
generate revenue. Adjustments may include losses due to shrinkage,
amounts consumed during processing, and contractual or regulatory host
committed volumes such as royalties. For the Upstream segment,
realizations include transfers between businesses.
Refining availability
Represents Solomon Associates’ operational availability for bp-operated
refineries, which is defined as the percentage of the year that a unit is
available for processing after subtracting the annualized time lost due to
turnaround activity and all planned mechanical, process and regulatory
downtime.
Refining marker margin (RMM)
The average of regional indicator margins weighted for bp’s crude refining
capacity in each region. Each regional marker margin is based on product
yields and a marker crude oil deemed appropriate for the region. The
regional indicator margins may not be representative of the margins
achieved by bp in any period because of bp’s particular refinery
configurations and crude and product slate.
Replacement cost (RC) profit or loss
Reflects the replacement cost of inventories sold in the period and is
arrived at by excluding inventory holding gains and losses from profit or
loss. RC profit or loss is the measure of profit or loss that is required to be
disclosed for each operating segment under IFRS. RC profit or loss for the
group is a non-GAAP measure. Management believes this measure is
useful to illustrate to investors the fact that crude oil and product prices
can vary significantly from period to period and that the impact on our
reported result under IFRS can be significant. Inventory holding gains and
losses vary from period to period due to changes in prices as well as
changes in underlying inventory levels. In order for investors to
understand the operating performance of the group excluding the impact
of price changes on the replacement of inventories, and to make
comparisons of operating performance between reporting periods, bp’s
management believes it is helpful to disclose this measure. The nearest
equivalent measure on an IFRS basis is profit or loss attributable to bp
346
bp Annual Report and Form 20-F 2020
RC profit or loss per share
Non-GAAP measure. Earnings per share is defined in Financial statements
– Note 11. RC profit or loss per share is calculated using the same
denominator. The numerator used is RC profit or loss attributable to bp
shareholders rather than profit or loss attributable to bp shareholders. bp
believes it is helpful to disclose the RC profit or loss per share because
this measure excludes the impact of price changes on the replacement of
inventories and allows for more meaningful comparisons between
reporting periods. The nearest equivalent measure on an IFRS basis is
basic earnings per share based on profit or loss for the period attributable
to bp shareholders. A reconciliation to GAAP information is provided on
page 348.
Renewables pipeline
Renewable projects satisfying criteria below to the point they can be
considered developed to FID :
Site based projects have obtained land exclusivity rights, or for PPA based
projects an offer has been made to the counterparty, or for auction
projects pre-qualification criteria has been met, or for acquisition projects
post a binding offer being accepted.
Reserves replacement ratio
The extent to which the year’s production has been replaced by proved
reserves added to our reserve base. The ratio is expressed in oil-
equivalent terms and includes changes resulting from discoveries,
improved recovery and extensions and revisions to previous estimates,
but excludes changes resulting from acquisitions and disposals.
Retail sites
Retail sites include sites operated by dealers, jobbers, franchisees or
brand licensees or joint venture (JV) partners, under the bp brand. These
may move to and from the bp brand as their fuel supply agreement or
brand licence agreement expires and are renegotiated in the normal
course of business. Retail sites are primarily branded bp, ARCO, Amoco,
Aral and Thorntons, and also includes sites in India through our Jio-bp JV.
Retail sites in growth markets
These are retail sites that are either bp branded or co-branded with our
partners in China, Mexico and Indonesia and also include sites in India
through our Jio-bp JV.
Return on average capital employed
Non-GAAP measure. Return on average capital employed (ROACE) is
underlying replacement cost profit, after adding back non-controlling
interest and interest expense net of tax (for 2016 and 2017 interest
expense was net of notional tax at an assumed 35%), divided by average
capital employed (total equity plus finance debt), excluding cash and cash
equivalents and goodwill. Interest expense is finance costs excluding
lease interest and the unwinding of the discount on provisions and other
payables before tax. bp believes it is helpful to disclose the ROACE
because this measure gives an indication of the company's capital
efficiency. The nearest GAAP measures of the numerator and
denominator are profit or loss for the period attributable to bp
shareholders and total equity respectively. The reconciliation of the
numerator and denominator is provided on page 349.
We are unable to present forward-looking information of the nearest
GAAP measures of the numerator and denominator for ROACE, because
without unreasonable efforts, we are unable to forecast accurately certain
adjusting items required to calculate a meaningful comparable GAAP
forward-looking financial measure. These items include inventory holding
gains or losses and interest net of tax, that are difficult to predict in
advance in order to include in a GAAP estimate.
Strategic convenience sites
Strategic convenience sites are retail sites, within the bp portfolio, which
both sell bp branded fuel and carry one of the strategic convenience
brands (e.g. M&S, Rewe to Go). To be considered a strategic convenience
brand the convenience offer should be a strategic differentiator in the
market in which it operates. Strategic convenience site count includes
sites under a pilot phase.
Subsidiary
An entity that is controlled by the bp group. Control of an investee exists
when an investor is exposed, or has rights, to variable returns from its
involvement with the investee and has the ability to affect those returns
through its power over the investee.
Surplus cash
Surplus cash refers to surplus of sources of cash including operating cash
flow, joint venture loan repayments and divestment proceeds, over uses,
including leases, Gulf of Mexico oil spill payments, hybrid servicing costs,
dividend payments and cash capital expenditure.
Tier 1 and tier 2 process safety events
Tier 1 events are losses of primary containment from a process of
greatest consequence – causing harm to a member of the workforce,
damage to equipment from a fire or explosion, a community impact or
exceeding defined quantities. Tier 2 events are those of lesser
consequence. These represent reported incidents occurring within bp’s
operational HSSE reporting boundary. That boundary includes bp’s own
operated facilities and certain other locations or situations.
Tight oil and gas
Natural oil and gas reservoirs locked in hard sandstone rocks with low
permeability, making the underground formation extremely tight.
Traded electricity
Traded electricity refers to sales data for physically delivered electricity.
Transition and low carbon investments
Capital expenditure on low carbon or other energy transition activities.
UK National Balancing Point
A virtual trading location for sale, purchase and exchange of UK natural
gas. It is the pricing and delivery point for the Intercontinental Exchange
natural gas futures contract.
Unconventionals
Resources found in geographic accumulations over a large area, that
usually present additional challenges to development such as low
permeability or high viscosity. Examples include shale gas and oil, coalbed
methane, gas hydrates and natural bitumen deposits. These typically
require specialized extraction technology such as hydraulic fracturing or
steam injection.
Underlying effective tax rate (ETR)
Non-GAAP measure. The underlying ETR is calculated by dividing taxation
on an underlying replacement cost (RC) basis by underlying RC profit or
loss before tax. Taxation on an underlying RC basis is taxation on a RC
basis for the period adjusted for taxation on non-operating items and fair
value accounting effects, and certain foreign exchange impacts on the
group’s tax charge for the period. Information on underlying RC profit or
loss is provided below. bp believes it is helpful to disclose the underlying
ETR because this measure may help investors to understand and
evaluate, in the same manner as management, the underlying trends in
bp’s operational performance on a comparable basis, period on period.
The nearest equivalent measure on an IFRS basis is the ETR on profit or
loss for the period. A reconciliation to GAAP information is provided on
page 348.
We are unable to present reconciliations of forward-looking information
for underlying ETR to ETR on profit or loss for the period, because without
unreasonable efforts, we are unable to forecast accurately certain
adjusting items required to present a meaningful comparable GAAP
forward-looking financial measure. These items include the taxation on
inventory holding gains and losses, non-operating items and fair value
accounting effects, that are difficult to predict in advance in order to
include in a GAAP estimate.
Underlying production
Production after adjusting for acquisitions and divestments and
entitlement impacts in our production-sharing agreements (PSAs). 2021
underlying production, when compared with 2020, is production after
adjusting for acquisitions and divestments, curtailments, and entitlement
impacts in our production-sharing agreements/contracts and technical
service contract.
Underlying replacement cost (RC) profit or loss
Non-GAAP measure. RC profit or loss after adjusting for non-operating
items and fair value accounting effects. Fair value accounting effects are
non-GAAP adjustments. See pages 304 and 305 for additional information
on the non-operating items and fair value accounting effects that are used
to arrive at underlying RC profit or loss in order to enable a full
understanding of the events and their financial impact. bp believes that
underlying RC profit or loss is a useful measure for investors because it is
a measure closely tracked by management to evaluate bp’s operating
performance and to make financial, strategic and operating decisions and
because it may help investors to understand and evaluate, in the same
manner as management, the underlying trends in bp’s operational
performance on a comparable basis, year on year, by adjusting for the
effects of these non-operating items and fair value accounting effects.
The nearest equivalent measure on an IFRS basis for the group is profit or
loss for the year attributable to bp shareholders. The nearest equivalent
measure on an IFRS basis for segments is RC profit or loss before
interest and taxation. A reconciliation to GAAP information is provided on
page 302.
Underlying replacement cost (RC) profit or loss per share
Non-GAAP measure. Earnings per share is defined Financial statements –
Note 11. Underlying RC profit or loss per share is calculated using the
same denominator. The numerator used is underlying RC profit or loss
attributable to bp shareholders rather than profit or loss attributable to bp
shareholders. bp believes it is helpful to disclose the underlying RC profit
or loss per share because this measure may help investors to understand
and evaluate, in the same manner as management, the underlying trends
in bp’s operational performance on a comparable basis, period on period.
The nearest equivalent measure on an IFRS basis is basic earnings per
share based on profit or loss for the period attributable to bp
shareholders. A reconciliation to GAAP information is provided on page
348.
Upstream plant reliability
bp-operated Upstream plant reliability is calculated taking 100% less the
ratio of total unplanned plant deferrals divided by installed production
capacity. Unplanned plant deferrals are associated with the topside plant
and where applicable the subsea equipment (excluding wells and
reservoir). Unplanned plant deferrals include breakdowns, which does not
include Gulf of Mexico weather related downtime.
Upstream unit production costs
Upstream unit production costs are calculated as production costs divided
by units of production. Production costs do not include ad valorem and
severance taxes. Units of production are barrels for liquids and thousands
of cubic feet for gas. Amounts disclosed are for bp subsidiaries only and
do not include bp’s share of equity-accounted entities.
West Texas Intermediate (WTI)
A light sweet crude oil, priced at Cushing, Oklahoma, which serves as a
benchmark price for purchases of oil in the US.
Working capital
Movements in inventories and other current and non-current assets and
liabilities as stated in the group cash flow statement.
Trade marks
Trade marks of the bp group appear throughout this report. They include:
Aral, ARCO, BP, bp pulse, Castrol, Amoco, Thorntons
Trade marks:
Amazon Web Services – a trademark of amazon.com, inc
REWE to Go – a registered trade mark of REWE.
bp Annual Report and Form 20-F 2020
347
Non-GAAP measures reconciliations
Reconciliation of basic earnings per ordinary share to RC profit (loss) per share and to underlying RC profit per
share
Profit (loss) for the yeara
Inventory holding (gains) losses, before tax
Taxation charge (credit) on inventory holding gains and losses
RC profit (loss) for the year
Net (favourable) adverse impact of non-operating items and fair value
accounting effects, before tax
Taxation charge (credit) on non-operating items and fair value accounting
effects
Underlying RC profit for the year
a Profit attributable to bp shareholders.
Per ordinary share – cents
2020
(100.42)
14.18
(3.29)
(89.53)
2019
19.84
(3.29)
0.77
17.32
2018
46.98
4.01
(0.99)
50.00
2017
17.20
(4.32)
1.14
14.02
2016
0.61
(8.52)
2.58
(5.33)
82.33
40.73
16.93
18.94
35.99
(20.94)
(28.14)
(8.81)
49.24
(3.23)
63.70
(1.65)
31.31
(16.87)
13.79
Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and adjusted ETR
Taxation (charge) credit
Taxation on profit or loss for the year
Adjusted for taxation on inventory holding gains and losses
Taxation on a RC profit or loss basis
Adjusted for taxation on non-operating items and fair value accounting
effects, and certain foreign exchange impacts on the group’s tax charge for
the period
Adjusted for the impact of US tax reform
Taxation on an underlying RC basis
Adjusted for the impact of the reduction in the rate of the UK North Sea
supplementary charge
Adjusted taxation
Effective tax rate
ETR on profit or loss for the year
Adjusted for inventory holding gains and losses
ETR on RC profit or loss
Adjusted for non-operating items and fair value accounting effects, and
certain foreign exchange impacts on the group’s tax charge for the period
Adjusted for the impact of US tax reform
Underlying ETR
Adjusted for the impact of the reduction in the rate of the UK North Sea
supplementary charge
Adjusted ETR
2020
4,159
667
3,492
4,235
—
(743)
—
(743)
2020
17
(1)
16
(30)
—
(14)
—
(14)
2019
(3,964)
(156)
(3,808)
2018
(7,145)
198
(7,343)
2017
(3,712)
(225)
(3,487)
1,788
—
522
121
1,184
(859)
(5,596)
(7,986)
(3,812)
—
(5,596)
—
(7,986)
—
(3,812)
2019
2018
2017
49
2
51
(15)
—
36
—
36
43
(1)
42
(5)
1
38
—
38
52
3
55
(9)
(8)
38
—
38
$ million
2016
2,467
(483)
2,950
3,162
—
(212)
434
(646)
%
2016
107
(31)
76
(69)
—
7
16
23
348
bp Annual Report and Form 20-F 2020
« See Glossary
Return on average capital employed (ROACE)
Profit (loss) for the year attributable to bp shareholders
Inventory holding (gains) losses, net of tax
Non-operating items and fair value accounting effects, net of tax
Underlying RC profit
Interest expense, net of taxa
Non-controlling interests (NCI)
Underlying RC profit attributable to bp shareholders and NCI, excluding
interest expense net of tax
Total equity
Finance debt
Capital employed (2020 average $163,332 million)
Less: Goodwill
Cash and cash equivalents
Average capital employed excluding goodwill and cash and cash equivalents
ROACE
a Calculated on a post-tax basis (for 2017 and earlier interest expense was net of notional tax at an assumed 35%).
2020
(20,305)
2,201
12,414
(5,690)
1,402
(424)
(4,712)
2019
2018
2017
4,026
(511)
6,475
9,990
1,744
164
11,898
9,383
603
2,737
12,723
1,583
195
14,501
3,389
(628)
3,405
6,166
924
79
7,169
$ million
2016
115
(1,114)
3,584
2,585
635
57
3,277
85,568
72,664
158,232
12,480
31,111
114,641
124,367
100,708
67,724
168,432
11,868
22,472
134,092
133,050
101,548
65,132
166,680
12,204
22,468
132,008
128,925
100,404
62,574
162,978
11,551
25,586
125,841
122,836
96,843
57,665
154,508
11,194
23,484
119,830
116,333
(3.8) %
8.9 %
11.2 %
5.8 %
2.8 %
Readily marketable inventory (RMI)
Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by bp's integrated supply and trading function (IST)
which could be sold to generate funds if required. Details of RMI balances and a reconciliation to GAAP information is set out below. Further
information on RMI, RMI at fair value, paid-up RMI and unpaid RMI is provided on page 345.
At 31 December
RMI at fair value
Paid-up RMI
Reconciliation of non-GAAP information
At 31 December
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet
Less: (a) inventories which are not oil and oil products and (b) oil and oil product inventories which are not risk-
managed by IST
RMI on IFRS basis
Plus: difference between RMI at fair value and RMI on an IFRS basis
RMI at fair value
Less: unpaid RMI at fair value
Paid-up RMI
2020
6,528
3,365
$ million
2019
6,837
3,217
2020
$ million
2019
16,873
20,880
(10,810)
6,063
465
6,528
(3,163)
3,365
(14,280)
6,600
237
6,837
(3,620)
3,217
The Directors’ report on pages 71-102, 105 (in respect of the remuneration committee report shown in grey only), 127-128, 231-258 and 301-349 was
approved by the board and signed on its behalf by Ben J. S. Mathews, company secretary on 22 March 2021.
BP p.l.c.
Registered in England and Wales No. 102498
« See Glossary
bp Annual Report and Form 20-F 2020
349
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to
sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/ Ben J. S. Mathews
Company secretary
22 March 2021
350
bp Annual Report and Form 20-F 2020
Cross reference to Form 20-F
A.
B.
C.
D.
A.
B.
C.
D.
A.
B.
C.
D.
E.
F.
G.
A.
B.
C.
D.
E.
A.
B.
C.
A.
B.
A.
B.
C.
D.
E.
F.
A.
B.
C.
D.
E.
F.
G.
H.
I.
A.
B.
C.
D.
Item 1.
Item 2.
Item 3.
Item 4.
Item 4A.
Item 5.
Item 6.
Item 7.
Item 8.
Item 9.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16A.
Item 16B.
Item 16C.
Item 16D.
Item 16E.
Item 16F.
Item 16G.
Item 17.
Item 18.
Item 19.
Identity of Directors, Senior Management and Advisors
Offer Statistics and Expected Timetable
Key Information
Selected financial data
Capitalization and indebtedness
Reasons for the offer and use of proceeds
Risk factors
Information on the Company
History and development of the company
Business overview
Organizational structure
Property, plants and equipment
Unresolved Staff Comments
Operating and Financial Review and Prospects
Operating results
Liquidity and capital resources
Research and development, patent and licenses
Trend information
Off-balance sheet arrangements
Tabular disclosure of contractual commitments
Safe harbor
Directors, Senior Management and Employees
Directors and senior management
Compensation
Board practices
Employees
Share ownership
Major Shareholders and Related Party Transactions
Major shareholders
Related party transactions
Interests of experts and counsel
Financial Information
Consolidated statements and other financial information
Significant changes
The Offer and Listing
Offer and listing details
Plan of distribution
Markets
Selling shareholders
Dilution
Expenses of the issue
Additional Information
Share capital
Memorandum and articles of association
Material contracts
Exchange controls
Taxation
Dividends and paying agents
Statements by experts
Documents on display
Subsidiary information
Quantitative and Qualitative Disclosures about Market Risk
Description of securities other than equity securities
Debt Securities
Warrants and Rights
Other Securities
American Depositary Shares
Defaults, Dividend Arrearages and Delinquencies
Material Modifications to the Rights of Security Holders and Use of
Proceeds
Controls and Procedures
Audit Committee Financial Expert
Code of Ethics
Principal Accountant Fees and Services
Exemptions from the Listing Standards for Audit Committees
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Change in Registrant’s Certifying Accountant
Corporate governance
Financial Statements
Financial Statements
Exhibits
Page
n/a
n/a
302, 332
n/a
n/a
67-70
8-14, 15-19, 25, 36, 38, 42-47, 108-112, 180-183, 230, 308-311, 318-319, 321-325, 330
33, 38, 42-47, 177-180, 184, 190, 192-195, 308-320
39-41, 45, 189, 190-191, 256-258, 308-321, 326
None
230
8-14, 15-19, 25, 38, 42-47, 67-70, 108-109, 111-112, 192-194, 204, 206-219, 308-325
158-159, 190, 204-225, 304-305
183, 326
8-19, 25, 38, 42-47, 108-109, 111-112, 308-320
180-183, 192-194, 307
307
329-330
74-79
39-41, 103-128, 197-203, 228-229
74-77, 94-99, 105
57-58, 229
57-58, 103-126, 197-203, 228
334-335
192-194, 326
n/a
130-258, 332
n/a
332
n/a
332
n/a
n/a
n/a
n/a
335-337
326
332
332-334
n/a
n/a
339
n/a
206-211
n/a
n/a
n/a
339
None
None
154, 326-327
76, 94-99
326
96-97, 229, 327
n/a
338
n/a
326
n/a
155-159
352
bp Annual Report and Form 20-F 2020
351
Information about this report
This document constitutes the Annual Report and Accounts in accordance
with UK requirements and the Annual Report on Form 20-F in accordance
with the US Securities Exchange Act of 1934, for BP p.l.c. for the year
ended 31 December 2020. A cross reference to Form 20-F requirements
is included on page 351.
This document contains the Strategic report on the inside front cover and
pages 1-70 and the Directors’ report on pages 71-102, 105 (in part only),
127-128, 231-258 and 301-349. The Strategic report and the Directors’
report together include the management report required by DTR 4.1 of
the UK Financial Conduct Authority’s Disclosure Guidance and
Transparency Rules. The Directors’ remuneration report is on pages
103-126. The consolidated financial statements of the group are on pages
129-230 and the corresponding reports of the auditor are on pages
130-154. The parent company financial statements of BP p.l.c. are on
pages 259-300.
The Directors’ statements (comprising the Statement of directors’
responsibilities; Risk management and internal control; Longer-term
viability; Going concern; and Fair, balanced and understandable), the
independent auditor’s report on the annual report and accounts to the
members of BP p.l.c., the parent company financial statements of BP
p.l.c. and corresponding auditor’s report and a non-GAAP measure of
operating cash flow excluding Gulf of Mexico oil spill payments« in the
tables on pages 41, 43 and 46 do not form part of bp’s Annual Report on
Form 20-F as filed with the SEC.
bp Annual Report and Form 20-F 2020 may be downloaded from bp.com/
annualreport. No material on the bp website, other than the items
identified as bp Annual Report and Form 20-F 2020, forms any part of this
document. References in this document to other documents on the bp
website, such as bp Energy Outlook, bp Sustainability Report, bp
Statistical Review of World Energy and bp Technology Outlook are
included as an aid to their location and are not incorporated by reference
into this document.
BP p.l.c. is the parent company of the bp group of companies. The
company was incorporated in 1909 in England and Wales and changed its
name to BP p.l.c. in 2001. Where we refer to the company, we mean BP
p.l.c. The company and each of its subsidiaries« are separate legal
entities. Unless otherwise stated or the context otherwise requires, the
term “BP” or "bp" and terms such as “we”, “us” and “our” are used in
this report for convenience to refer to one or more of the members of the
bp group instead of identifying a particular entity or entities. Information in
this document reflects 100% of the assets and operations of the
company and its subsidiaries that were consolidated at the date or for the
periods indicated, including non-controlling interests.
The company’s primary share listing is the London Stock Exchange. In the
US, the company’s securities are traded on the New York Stock Exchange
(NYSE) in the form of ADSs (see page 332 for more details) and in
Germany in the form of a global depositary certificate representing bp
ordinary shares traded on the Frankfurt, Hamburg and Dusseldorf Stock
Exchanges.
The term ‘shareholder’ in this report means, unless the context otherwise
requires, investors in the equity capital of BP p.l.c., both direct and
indirect. As the company's shares, in the form of ADSs, are listed on the
NYSE, an Annual Report on Form 20-F is filed with the SEC. Ordinary
shares are ordinary fully paid shares in BP p.l.c. of 25 cents each.
Preference shares are cumulative first preference shares and cumulative
second preference shares in BP p.l.c. of £1 each.
Registered office and
our worldwide headquarters:
BP p.l.c.
1 St James’s Square
Our agent in the US:
BP America Inc.
501 Westlake Park Boulevard
London SW1Y 4PD
Houston, Texas 77079
UK
US
Tel +44 (0)20 7496 4000
Tel +1 281 366 2000
Registered in England and Wales No. 102498.
London Stock Exchange symbol ‘BP.’
Exhibits
The following documents are filed in the Securities and Exchange
Commission (SEC) EDGAR system, as part of this Annual Report on Form
20-F, and can be viewed on the SEC’s website.
Exhibit 1
Exhibit 2
Exhibit 4.1
Exhibit 4.4
Memorandum and Articles of Association of BP
p.l.c.***†
Description of rights of each class of securities
registered under Section 12 of the Securities
Exchange Act of 1934†
The BP Executive Directors’ Incentive Plan**†
Director’s Service Agreement for B
Looney****†
Exhibit 4.7
Director’s Service Contract for M Auchincloss†
Exhibit 4.10
Exhibit 8
Exhibit 11
Exhibit 12
Exhibit 13
Exhibit 15.1
Exhibit 15.2
Exhibit 15.3
Exhibit 15.4
Exhibit 15.5
Exhibit 15.6
Exhibit 15.7
Exhibit 15.8
Exhibit 99.1
Exhibit 99.2
Exhibit 101
Exhibit 104
The BP Share Award Plan 2015***†
Subsidiaries (included as Note 37 to the
Financial Statements)
Code of Ethics*†
Rule 13a – 14(a) Certifications†
Rule 13a – 14(b) Certifications#†
Consent of DeGolyer and MacNaughton†
Report of DeGolyer and MacNaughton†
Consent of Netherland, Sewell & Associates†
Report of Netherland, Sewell & Associates†
Consent Decree***†
Gulf states Settlement Agreement***†
Consent of Deloitte LLP†
Consent of Ernst & Young LLC regarding
opinion in Exhibit 99.1†
Consolidated financial statements of Rosneft
Oil Company as at and for the years ended 31
December 2020 (unaudited) and 2019†
Consolidated financial statements of Rosneft
Oil Company as at and for the years ended 31
December 2018 (unaudited) and 2017
(unaudited)†
Inline XBRL data files
Cover page interactive data file (formatted as
Inline XBRL and contained in Exhibit 101)
*
Incorporated by reference to the company’s Annual Report on Form 20-F for
the year ended 31 December 2009.
**
Incorporated by reference to the company’s Annual Report on Form 20-F for
the year ended 31 December 2014.
***
Incorporated by reference to the company’s Annual Report on Form 20-F for
the year ended 31 December 2015.
****
Incorporated by reference to the company’s Annual Report on Form 20-F for
#
†
the year ended 31 December 2019.
Furnished only.
Included only in the annual report filed in the Securities and Exchange
Commission EDGAR system.
The total amount of long-term securities of BP p.l.c. and its subsidiaries
under any one instrument does not exceed 10% of their total assets on a
consolidated basis.
The company agrees to furnish copies of any or all such instruments to
the SEC on request.
Paper: Nautilus Super White is a premium ecological paper. It is made from 100% post-consumer
waste recycled paper and is FSC® (Forest Stewardship Council®) certified. The paper also holds the
EU Ecolabel certification. The manufacturing mill also holds ISO 14001 environmental certification.
Printed in the UK by Pureprint Group.
352
bp Annual Report and Form 20-F 2020
« See Glossary
Copies
You can order bp’s
printed publications
free of charge from
bp.com/annualreport.
US and Canada
Issuer Direct
Toll-free: +1 888 301 2505
bpreports@issuerdirect.com
UK and rest of world
bp Distribution Services
Tel: +44 (0)870 241 3269
bpdistributionservices@bp.com
Feedback
Your feedback is important
to us. You can contact the
corporate reporting team at
corporatereporting@bp.com
b
p
A
n
n
u
a
l
R
e
p
o
r
t
a
n
d
F
o
r
m
2
0
-
F
2
0
2
0
bp’s corporate reporting suite
includes information about our
financial and operating
performance, sustainability
performance and also on global
energy trends and projections.
Annual Report
and Form 20-F 2020
Details of our financial
and operating performance
in print and online.
bp.com/annualreport
Energy Outlook
Provides our projections
of future energy trends
and factors that could
affect them.
bp.com/energyoutlook
Sustainability
Report 2020
Details of our sustainability
performance with additional
information online.
bp.com/sustainability
Statistical Review
of World Energy 2020
An objective review of
key global energy trends.
bp.com/statisticalreview
Financial and Operating
Information 2016-2020
Five-year financial and operating
data in PDF and Excel format.
bp.com/financialandoperating
© BP p.l.c. 2021